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EX-99 - EX-99 - PANHANDLE OIL & GAS INCphx-ex99_11.htm
EX-32.2 - EX-32.2 - PANHANDLE OIL & GAS INCphx-ex322_9.htm
EX-32.1 - EX-32.1 - PANHANDLE OIL & GAS INCphx-ex321_10.htm
EX-31.2 - EX-31.2 - PANHANDLE OIL & GAS INCphx-ex312_12.htm
EX-31.1 - EX-31.1 - PANHANDLE OIL & GAS INCphx-ex311_6.htm
EX-23.2 - EX-23.2 - PANHANDLE OIL & GAS INCphx-ex232_13.htm
EX-23.1 - EX-23.1 - PANHANDLE OIL & GAS INCphx-ex231_8.htm
EX-10.9 - EX-10.9 - PANHANDLE OIL & GAS INCphx-ex109_600.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

 

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2019

Commission File Number:     001-31759

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

 

OKLAHOMA

 

73-1055775

(State or other jurisdiction of incorporation

 

(I.R.S. Employer Identification No.)

or organization)

 

 

 

 

 

Grand Centre, Suite 300, 5400 N. Grand Blvd.

Oklahoma City, OK

 

73112

(Address of principal executive offices)

 

(Zip code)

 

 

 

Registrant's telephone number:   (405) 948-1560

 

 

 

 

 

Securities registered under Section 12(b) of the Act:

 

 

Title of each classTrading Symbol(s)Name of each exchange on which registeredClass A Common Stock, $0.01666 par valuePHXNew York Stock Exchange

 

Securities registered under Section 12(g) of the Act: None

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Exchange Act of 1934.           Yes      X   No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.           Yes      X   No

 


 

(Facing Sheet Continued)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.      X  Yes           No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).      X   Yes           No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Securities Exchange Act of 1934. (Check one):

 

Large accelerated filer        

 

Accelerated filer     X  

 

Non-accelerated filer        

 

Smaller reporting company       

Emerging growth company       

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.         Yes          No

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).           Yes      X   No

The aggregate market value of the voting stock held by non-affiliates of the registrant, computed by using the $15.70 per share closing price of registrant's Class A Common Stock, as reported by the New York Stock Exchange at March 31, 2019, was $246,376,520.

As of December 1, 2019, the Registrant had 16,339,255 shares of Class A Common Stock outstanding.

Documents Incorporated By Reference

Portions of the definitive Proxy Statement of Panhandle Oil and Gas Inc. (to be filed no later than 120 days after September 30, 2019) relating to the Annual Meeting of Stockholders to be held on March 3, 2020, are incorporated into Part III of this Form 10-K.

 

 

 


 

T A B L E   O F   C O N T E N T S

 

 

 

 

 

Page

 

 

Special Note Regarding Forward-Looking Statements

 

 

 

 

Glossary of Certain Terms

 

 

PART I

 

 

 

 

Item 1

 

Business

 

1

Item 1A

 

Risk Factors

 

9

Item 1B

 

Staff Comments

 

27

Item 2

 

Properties

 

27

Item 3

 

Legal Proceedings

 

38

Item 4

 

Mine Safety Disclosures

 

38

 

 

 

 

 

PART II

 

 

 

 

Item 5

 

Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

39

Item 6

 

Selected Financial Data

 

42

Item 7

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

43

Item 7A

 

Quantitative and Qualitative Disclosures about Market Risk

 

60

Item 8

 

Financial Statements and Supplementary Data

 

62

Item 9

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

104

Item 9A

 

Controls and Procedures

 

104

Item 9B

 

Other Information

 

105

 

 

 

 

 

PART III

 

 

 

 

Item 10-14

 

Incorporated by Reference to Proxy Statement

 

106

 

 

 

 

 

PART IV

 

 

 

 

Item 15

 

Exhibits, Financial Statement Schedules and Reports on Form 8-K

 

107

 


 


 

Special Note Regarding Forward Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements. Forward-looking statements may include, but are not limited to statements relating to: our ability to execute our business strategies; the volatility of realized oil and natural gas prices; the level of production on our properties; estimates of quantities of oil, NGL and natural gas reserves and their values; general economic or industry conditions; legislation or regulatory requirements; conditions of the securities markets; our ability to raise capital; changes in accounting principles, policies or guidelines; financial or political instability; acts of war or terrorism; title defects in the properties in which we invest; and other economic, competitive, governmental, regulatory or technical factors affecting our properties, operations or prices.

We caution you that the forward-looking statements contained in this Form 10-K are subject to risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended September 30, 2019 (the “2019 Annual Report on Form 10-K” or this “Annual Report”), and all quarterly reports on Form 10-Q filed subsequently thereto.

Should one or more of the risks or uncertainties described above or elsewhere in our 2019 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law.

Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.


 


 

Glossary of Certain Terms

 

The following is a glossary of certain accounting, oil and natural gas industry and other defined terms used in this Annual Report:

 

Bbl

barrel.

Bcf

billion cubic feet.

Bcfe

natural gas stated on a Bcf basis and crude oil and natural gas liquids converted to a billion cubic feet of natural gas equivalent by using the ratio of one million Bbl of crude oil or natural gas liquids to six Bcf of natural gas.

Board

the board of directors of the Company.

BTU

British Thermal Units.

Common Stock

the Company’s Class A Common Stock.

completion

the post-drilling processes of preparing a well for the production of crude oil and/or natural gas.

conventional

an area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.

DD&A

depreciation, depletion and amortization.

developed acreage

the number of acres allocated or assignable to productive wells or wells capable of production.

development well

a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

dry gas

natural gas that remains in a gaseous state in the reservoir and does not produce large quantities of liquid hydrocarbons when brought to the surface. Also, may refer to gas that has been processed or treated to remove a majority of natural gas liquids.

dry hole

exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.

EBITDA

earnings before interest, taxes, depreciation and amortization (including impairment). This is a Non-GAAP measure.

ESOP

the Panhandle Oil and Gas Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan.

exploratory well

a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir.

FASB

the Financial Accounting Standards Board.

field

an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

formation

a layer of rock, which has distinct characteristics that differ from nearby rock.

G&A

general and administrative expenses.

GAAP

generally accepted accounting principles.

gross acres or gross wells

the total acres or wells in which an interest is owned.

 


 

held by production or

HBP

an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.

horizontal drilling

a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.

hydraulic fracturing

a process involving the high-pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production.

LOE

lease operating expense.

Mcf

thousand cubic feet.

Mcfd

thousand cubic feet per day.

Mcfe

natural gas stated on an Mcf basis and crude oil and natural gas liquids converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil or natural gas liquids to six Mcf of natural gas.

Mcfed

natural gas stated on an Mcf basis and crude oil and natural gas liquids converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil or natural gas liquids to six Mcf of natural gas per day.

Mmbtu

million BTU.

Mmcf

million cubic feet.

Mmcfe

natural gas stated on an Mmcf basis and crude oil and natural gas liquids converted to a million cubic feet of natural gas equivalent by using the ratio of one thousand Bbl of crude oil or natural gas liquids to six Mmcf of natural gas.

minerals, mineral acres or mineral interests

fee mineral acreage owned in perpetuity by the Company.

net acres or net wells

the sum of the fractional interests owned in gross acres or gross wells.

NGL

natural gas liquids.

NRI

net revenue interest.

NYMEX

the New York Mercantile Exchange.

OPEC

Organization of Petroleum Exporting Countries.

PDP

proved developed producing.

play

term applied to identified areas with potential oil, NGL and/or natural gas reserves.

production or produced

volumes of oil, NGL and natural gas that have been both produced and sold.

proved reserves

the quantities of crude oil and natural 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 renewal is reasonably certain.

proved developed reserves

reserves expected to be recovered through existing wells with existing equipment and operating methods.

 


 

proved undeveloped reserves or

PUD

proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

PV-10

estimated pre-tax present value of future net revenues discounted at 10% using SEC rules.

royalty interest

well interests in which the Company does not pay a share of the costs to drill, complete and operate a well, but receives a smaller proportionate share (as compared to a working interest) of production.

SEC

the United States Securities and Exchange Commission.

unconventional

an area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands, and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.

undeveloped acreage

acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

working interest

well interests in which the Company pays a share of the costs to drill, complete and operate a well and receives a proportionate share of production.

WTI

West Texas Intermediate.

 

As used herein, the “Company,” “Panhandle,” “we,” “us” and “our” refer to Panhandle Oil and Gas Inc. and its predecessors and subsidiaries unless the context requires otherwise.

 

Fiscal year references

All references to years in this report, unless otherwise noted, refer to the Company’s fiscal year end of September 30. For example, references to 2019 mean the fiscal year ended September 30, 2019.

 

References to oil and natural gas properties

References to oil and natural gas properties inherently include NGL associated with such properties.

 

 

 


 

PART I

ITEM 1.

Business

Overview

Panhandle Oil and Gas Inc. was founded in Range, Texas County, Oklahoma, in 1926, as Panhandle Cooperative Royalty Company. The Company operated as a cooperative until 1979, when it merged into Panhandle Royalty Company, and its shares became publicly traded. On April 2, 2007, the Company’s name was changed to Panhandle Oil and Gas Inc.

Panhandle Oil and Gas Inc. is an Oklahoma City-based company focused on perpetual oil and natural gas mineral ownership in resource plays in the United States. In addition, as part of our evolution as a company, we own interests in leasehold acreage and non-operated interests in oil and natural gas properties. Historically, we have participated with a working interest on some of our mineral and leasehold acreage.

Strategic Focus on Mineral Ownership

During fiscal 2019, the Company made the strategic decision to focus on perpetual oil and natural gas mineral ownership and growth through mineral acquisitions and the development of its significant mineral acreage inventory in its core areas of focus. In accordance with this strategy, the Company plans to cease taking any working interest positions on its mineral and leasehold acreage going forward. The Company believes that its strategy to focus on mineral ownership is the best path to giving our stockholders the greatest risk-weighted returns on their investments going forward.

A “mineral fee” is an interest in real property in which the owner owns all of the rights to the minerals under the surface forever, as compared to a mineral lease in which the lessee’s rights end at the expiration of the lease term or after there is no longer production on the lease. Generally, the mineral interest owner of a mineral fee interest reserves a non-cost bearing royalty interest upon the lease of such oil, gas, and other minerals to an oil and gas exploration and development company. Such companies will lease such mineral interest from the fee mineral owner for a term with the expectation of producing oil and gas, thereby generating free cash flow from bonuses and royalties. As referenced above, Panhandle’s leasehold interests are non-operated working interests on the lease of the minerals from the mineral fee owner. These non-operated working interests require Panhandle to contribute its proportionate share of the costs incurred by the operator in the development of such minerals. As discussed above and further below, Panhandle no longer expects to participate with such working interests going forward. Panhandle’s mineral and leasehold properties are located primarily in Oklahoma, North Dakota, Texas, Arkansas and New Mexico. The majority of our oil, NGL and natural gas production is from wells located in Oklahoma, North Dakota, Texas and Arkansas.

Although a significant amount of our revenues is currently derived from the production and sale of oil, NGL and natural gas on our working interests, a growing portion of our revenues is derived from royalties granted from the production and sale of oil, NGL and natural gas. These royalties are tied to ownership of mineral acreage, and this ownership is perpetual, unless sold by

1


 

the Company. Royalties are due and payable to the Company whenever oil, NGL or natural gas is produced and sold from wells located on the Company’s mineral acreage.

We owned approximately 258,231 perpetual mineral acres as of September 30, 2019, as detailed in the table below:

Play

 

Net Acres

 

 

% Producing

 

 

% Leased But Not Producing

 

 

% Unleased

 

SCOOP/STACK

 

 

11,171

 

 

62%

 

 

13%

 

 

25%

 

Bakken/Three Forks

 

 

3,095

 

 

90%

 

 

0%

 

 

10%

 

Arkoma Stack

 

 

11,592

 

 

64%

 

 

2%

 

 

34%

 

Permian

 

 

39,275

 

 

10%

 

 

14%

 

 

76%

 

Fayetteville

 

 

9,903

 

 

72%

 

 

0%

 

 

28%

 

Eagle Ford

 

 

-

 

 

0%

 

 

0%

 

 

0%

 

Other

 

 

183,195

 

 

18%

 

 

3%

 

 

79%

 

Total:

 

 

258,231

 

 

24%

 

 

5%

 

 

71%

 

Approximately 71% of our net mineral position is currently unleased, providing us the opportunity to generate additional cash flow from bonus payments and royalties without spending additional capital. We also own leases on 17,199 net acres primarily in Oklahoma and working interests, royalty interests or both, in 6,496 producing oil and natural gas wells and 120 wells in the process of being drilled or completed.

Exploration and development of our oil and natural gas properties are conducted by oil and natural gas exploration and production companies, primarily larger independent operating companies. We do not operate any of our oil and natural gas properties. While we previously have been an active working interest participant for many years in wells drilled on the Company’s mineral and leasehold acreage, our current focus is on growth through mineral acquisitions and through development of our significant mineral acreage inventory in our core areas of focus.

We intend to maximize value to our stockholders through the acquisition of mineral acreage, in the cores of resource plays, with substantial undeveloped opportunities; divestiture of non-core minerals with limited optionality when the amount negotiated exceeds our projected total value; and aggressive leasing of our mineral holdings.

Our Business Strategy

Our principal business objective is to maximize value to our stockholders. At the end of 2019, the Company made the strategic decision to cease taking any working interest positions on its mineral and leasehold acreage going forward. The Company has decided to focus on growth through mineral acquisitions and through development of its significant mineral acreage inventory in its core areas of focus. The Company believes that this is the best path to giving our stockholders the greatest risk-weighted returns on their investments going forward. We intend to accomplish this objective by executing the following corporate strategies:

 

Manage Mineral and Leasehold Assets as a Portfolio to Maximize Value. We plan to manage our mineral and leasehold assets through the following:

2


 

 

o

Growing our mineral fee holdings by acquiring mineral acreage, in the cores of oil and liquids-rich resource plays, with substantial undeveloped opportunities that meet or exceed our corporate return threshold;

 

o

Aggressively leasing our mineral holdings;

 

o

Selectively divesting non-core minerals with limited optionality when the amount negotiated exceeds our projected total value; and

 

o

Optimizing our leasehold and working interest positions through strategic sales and farmouts for overriding royalty interests or cash payments.

 

Maintain Strong Financial Position. We plan to maintain our strong financial position through the following:

 

o

Allocating capital for highest stockholder returns;

 

o

Utilize in-house technology and engineering expertise as a competitive advantage;

 

o

Maintaining conservative leverage ratio to ensure the ability to survive and thrive in all business and commodity cycles; and

 

o

Hedging to manage commodity risk and to protect our balance sheet.

Our Business Strengths

We believe the following attributes position Panhandle to achieve its objectives:

 

Focused on Perpetual Mineral Fee Ownership. Our strategic decision to focus on mineral ownership provides us with the perpetual option to benefit from future development and technology. We are focused on generating meaningful revenues through lease bonuses and royalty interests and these revenues have been a growing proportion of our total revenues when compared to our working interests. We owned approximately 258,231 net mineral acres as of September 30, 2019, held principally in Oklahoma, North Dakota, Texas, Arkansas and New Mexico. We also held leases on 17,199 net acres primarily in Oklahoma; and working interests, royalty interests, or both, in 6,496 producing oil and natural gas wells and 120 wells in the process of being drilled or completed.

 

Mineral and Leasehold Ownership in Multiple Top-Tier Resource Plays. We own mineral and leasehold interests in multiple top-tier resource plays in the United States, including positions in the SCOOP/STACK, Bakken/Three Forks, Arkoma Woodford, Eagle Ford, Permian Basin and Fayetteville plays. A significant portion of our revenues is derived from the production and sale of oil, NGL and natural gas from these positions. During the fiscal year ended September 30, 2019, production on our acreage was 28,382 Mcfed with approximately 19%, 13% and 68% being derived from oil, NGL and natural gas, respectively.

3


 

 

Material Undeveloped Mineral Position in Oil and Gas Producing Basins. Over 70% of our mineral fee position is currently not leased or in production, providing us with significant value and the opportunity to generate additional cash flows from bonus payments and royalties without deploying additional capital. We have an active program in place focused on leasing open acreage to generate additional lease bonus revenue and future royalty revenue.

 

Strong and Flexible Financial Position. We maintain a strong and flexible financial position through the management of our debt, cash and working capital. We evaluate our position, and we hedge to manage commodity price risk and to protect our balance sheet.

 

Experienced Management and Technical Team. We have a management and technical team with extensive experience in the oil and gas industry. Our management and technical team average over 20 years of industry experience in each applicable area of the Company, including accounting, land, geology, engineering and mergers and acquisitions.

Principal Products and Markets

The Company derives revenue through its bonus and royalty payments and from working interests on its mineral and leasehold acreage. The Company’s principal products from the production associated with its non-operated interests, in order of revenue generated, are crude oil, natural gas and NGL. These products are generally sold by our well operators to various purchasers, including pipeline and marketing companies, which service the areas where the Company’s producing wells are located. Since the Company does not operate any of the wells in which it owns an interest, it relies on the operating expertise of numerous companies that operate wells in which the Company owns interests. This includes expertise in the drilling and completion of new wells, producing well operations and, in most cases, the marketing or purchasing of production from the wells. Oil, NGL and natural gas sales are principally handled by the well operator. Payment for oil, NGL and natural gas sold is received by the Company from the well operator or the contracted purchaser.

Prices of oil, NGL and natural gas are dependent on numerous factors beyond the Company’s control, including supply and demand, competition, weather, international events and circumstances, actions taken by OPEC and economic, political and regulatory developments. Since demand for natural gas is subject to weather conditions, prices received for the Company’s natural gas production may be subject to seasonal variations.

The Company enters into price risk management financial instruments (derivatives) to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas and protect its return on investments. The derivative contracts apply only to a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative contracts expose the Company to risk of financial loss and may limit the benefit of future increases in oil and natural gas prices. Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the derivative contracts entered into by the Company.

4


 

Competitive Business Conditions

The oil and natural gas industry is highly competitive, particularly in the search for new fee mineral interests and oil, NGL and natural gas reserves. Many factors beyond its control affect Panhandle’s competitive position. Some of these factors include: the quantity and price of foreign oil imports; domestic supply and deliverability of oil, NGL and natural gas; changes in prices received for oil, NGL and natural gas production; business and consumer demand for refined oil products, NGL and natural gas; and the effects of federal, state and local regulation of the exploration for, production of and sales of oil, NGL and natural gas (see Item 1A – “Risk Factors”). Many companies have substantially greater resources than we have, and such companies may have more resources to evaluate, bid for and purchase more mineral fee, royalty and similar interests than our financial or human resources permit.

The Company does not operate any of the wells in which it has an interest; rather, it relies on companies with greater resources, staff, equipment, research and experience for operation of wells in both the drilling and production phases. The Company’s business strategy is to use its strong financial base and its mineral and leasehold acreage ownership, coupled with its own geologic and economic evaluations, to lease or farmout its mineral or leasehold acreage while retaining a royalty interest and to acquire new mineral acreage. We believe this strategy allows the Company to compete effectively in a competitive mineral market; however, our ability to acquire additional mineral fee, royalty and similar interests in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Major Customers

The Company’s oil, NGL and natural gas production is sold, in most cases, through our lessees or well operators to numerous different purchasers.

Regulation of the Oil and Natural Gas Industry

General

As the owner of mineral fee interests and non-operating working interests, we do not have any employees or contractors in the field and we are not directly subject to many of the regulations of the oil and gas industry. The following disclosure describes regulations and environmental matters more directly associated with operators of oil and natural gas properties, including our current operators. Since the Company does not operate any wells in which it owns an interest, actual compliance with many laws and regulations is controlled by the well operators, with Panhandle being responsible only for its proportionate share of the costs, if any, involved on wells in which it owns a working interest.

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision. Some of these requirements carry substantial penalties for failure to comply.

5


 

Although we are generally not directly subject to many of the rules, regulations and limitations impacting the oil and natural gas exploration and production industry as whole, the operators who operate on our properties may be impacted by such rules and regulations and we may be responsible for our proportionate share of costs for wells on which we own a working interest. While this may provide the Company with some insulation from compliance costs applicable to our operator-lessees, we may still be indirectly impacted by operator regulations because our revenue stream depends on operators and the production of oil, NGL and natural gas.

Regulation of Drilling and Production

The production of oil and natural gas is subject to regulation under federal, state and local statutes, rules, orders and regulations. These statutes and regulations require that operators obtain permits for drilling operations and drilling bonds, as well as require reports concerning operations. Additionally, states where we own mineral and leasehold interests have enacted regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that can be produced from wells and to limit the number of wells or the locations at which can be drilled. Additionally, some states where we hold mineral or leasehold interests may impose a production or severance tax with respect to the production and sale of oil, NGL and natural gas within its jurisdiction.

Regulation of Transportation of Oil

The sale and transportation of our crude oil is generally undertaken by the operators (or by third parties at the direction of the operators) of our properties. Sales of crude oil, condensate and NGL are not currently regulated and are made at negotiated prices; however, Congress could reenact price controls in the future.

Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (the “FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs.

Regulation of Transportation and Sale of Natural Gas

The sale and transportation of our natural gas is generally undertaken by the operators (or by third parties at the direction of the operators) of our properties. Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the

6


 

Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

The FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state.

Environmental Compliance and Risks

Our operators and properties are impacted by extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment and relating to safety and health.

Oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Historically, most of the environmental regulation of oil and gas production has been left to state regulatory boards or agencies in those jurisdictions where there is significant oil and natural gas production, with limited direct regulation by such federal agencies as the Environmental Protection Agency. However, there are various regulations issued by the Environmental Protection Agency (“EPA”) and other governmental agencies that would govern significant spills, blow-outs or uncontrolled emissions.

Many states, including states where we own properties have enacted oil and natural gas regulations that apply to the drilling, completion and operations of wells and the disposal of waste oil and salt water. The operators of our properties are subject to such regulations. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

At the federal level, among the more significant laws and regulations that may affect our business and the oil and natural gas industry are: The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund; the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act, also known as “RCRA,”;

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the Clean Air Act; Federal Water Pollution Control Act of 1972, or the Clean Water Act; and the Safe Drinking Water Act of 1974.

Since the Company does not operate any wells in which it owns an interest, actual compliance with environmental laws is controlled by the well operators, with Panhandle being responsible for its proportionate share of the costs involved on wells that we own a working interest. As such, the Company has no knowledge of any instances of non-compliance with existing laws and regulations. The Company maintains insurance coverage at levels which are customary in the industry, but is not fully insured against all environmental risks.

Taxes

The Company’s oil and natural gas properties are subject to various taxes, such as gross production taxes and, in some cases, ad valorem taxes. The Company pays ad valorem taxes on minerals owned in ten states.

Employees

At September 30, 2019, Panhandle employed 22 persons. In addition to serving as the Interim Chief Executive Officer, Mr. Chad Stephens, also serves as a director of the Company.

Corporate Office

The Company’s office is located at Grand Centre, Suite 300, 5400 N. Grand Blvd., Oklahoma City, OK 73112. Our telephone number is (405) 948-1560 and facsimile number is (405) 948-2038. The Company’s website is www.panhandleoilandgas.com.

Available Information

We make available free of charge on our website (www.panhandleoilandgas.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC.

We also make available within the “Corporate Governance” section under the “Investors” section of our website our Code of Ethics & Business Practices, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines, Lead Independent Director Charter and Audit Committee, Corporate Governance and Nominating Committee and Compensation Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Ethics & Business Practices and Code of Ethics for Senior Financial Officers for our principal executive and senior financial officers. Copies of our Code of Ethics & Business Practices and Code of Ethics for Senior Financial Officers are available free of charge by writing us at: Panhandle Oil and Gas Inc., Attn: Robb Winfield, 5400 N. Grand Blvd., Suite 300, Oklahoma City, OK 73112.

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ITEM 1A.

Risk Factors

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating the Company’s business and future prospects. If any of the following risk factors should occur, the Company’s financial condition could be materially impacted, and the holders of our securities could lose part or all of their investment in Panhandle. As the owner of mineral fee interests and non-operating working interests, we do not operate any oil and natural gas properties, and we do not have any employees or contractors in the field. As such, the risks associated with oil and gas operations only affect us indirectly and typically through our non-operating working interests as we proportionately share in the costs of operating such wells. The risk factors described below are not exhaustive, and investors are encouraged to perform their own investigation with respect to the Company and its business. Investors should also read the other information in this Form 10-K, including the financial statements and related notes.

Risks Related to our Business

The volatility of oil and natural gas prices, and particularly the ongoing decline in those prices, due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

The supply of and demand for oil, NGL and natural gas impact the prices we realize on the sale of these commodities and, in turn, materially affect the Company’s financial results. Oil, NGL and natural gas prices have historically been, and will likely continue to be, volatile. The prices for oil, NGL and natural gas are subject to wide fluctuation in response to a number of factors beyond our control, including:

 

domestic and worldwide economic conditions;

 

economic, political, regulatory and tax developments;

 

market uncertainty;

 

changes in the supply of and demand for oil, NGL and natural gas;

 

availability and capacity of necessary transportation and processing facilities;

 

commodity futures trading;

 

regional price differentials;

 

differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);

 

differing quality and NGL content of natural gas produced;

 

weather conditions;

 

conservation and environmental protection efforts;

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the level of imports and exports of oil, NGL and natural gas;

 

political instability or armed conflicts in major oil and natural gas producing regions;

 

actions taken by OPEC or other major oil, NGL and natural gas producing or consuming countries;

 

competition from alternative sources of energy; and

 

technological advancements affecting energy consumption and energy supply.

Our revenues, operating results, cash available for distribution and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

 

the domestic and foreign supply of oil and natural gas;

 

the level of prices and expectations about future prices of oil and natural gas;

 

the level of global oil and natural gas exploration and production;

 

the cost of exploring for, developing, producing and delivering oil and natural gas;

 

the price and quantity of foreign imports;

 

political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

 

the ability of members of the OPEC to agree to and maintain oil price and production controls;

 

speculative trading in crude oil and natural gas derivative contracts;

 

the level of consumer product demand;

 

weather conditions and other natural disasters;

 

risks associated with operating drilling rigs;

 

technological advances affecting energy consumption;

 

the price and availability of alternative fuels;

 

domestic and foreign governmental regulations and taxes;

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the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

 

the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and

 

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. If the prices of oil and natural gas remain at current levels or decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be determined at the discretion of our lenders.

Low oil, NGL and natural gas prices for a prolonged period of time would have a material adverse effect on the Company.

The volatility of the energy markets makes it extremely difficult to predict future oil, NGL and natural gas price movements with any certainty. Oil, NGL and natural gas prices continued to fluctuate in fiscal year 2019 and have fluctuated significantly over the past several months. The Company’s financial position, results of operations, access to capital and the quantities of oil, NGL and natural gas that may be economically produced would be negatively impacted if oil, NGL and natural gas prices were low for an extended period of time. The ways in which low prices could have a material negative effect include:

 

significantly decrease the number of wells operators drill on the Company’s acreage, thereby reducing our production and cash flows;

 

cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves and maintain or increase production;

 

future undiscounted and discounted net cash flows from producing properties would decrease, possibly resulting in recognition of impairment expense;

 

certain reserves may no longer be economic to produce, leading to lower proved reserves, production and cash flow;

 

access to sources of capital, such as equity and debt markets, could be severely limited or unavailable; and

 

the Company may incur a reduction in the borrowing base on its credit facility.

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Lower oil, NGL and natural gas prices or negative adjustments to oil, NGL and natural gas reserves may result in significant impairment charges.

The Company has elected to utilize the successful efforts method of accounting for its oil and natural gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and development dry holes are capitalized and amortized by property using the unit-of-production method (the ratio of oil, NGL and natural gas volumes produced to total proved or proved developed reserves) as oil, NGL and natural gas are produced.

All long-lived assets, principally the Company’s oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset on our books may be greater than its future net cash flows. The need to test a property for impairment may result from declines in oil, NGL and natural gas sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. The decision to not participate in future development on our leasehold acreage can trigger a test for impairment. Also, once assets are classified as held for sale, they are reviewed for impairment. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded. If an impairment charge is recognized, cash flow from operating activities is not impacted, but net income and, consequently, stockholders’ equity are reduced. In periods when impairment charges are incurred, it could have a material adverse effect on our results of operations. See Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplemental Data” for further discussion on impairment under the heading “Impairment.”

Our future success depends on finding, developing or acquiring additional reserves and failure to find or acquire additional reserves will cause reserves and production to decline materially from their current levels.

The rate of production from oil and natural gas properties generally declines as reserves are depleted. The Company’s proved reserves will decline materially as reserves are produced except to the extent that the Company acquires additional properties containing proved reserves, conducts additional successful exploration and development drilling, successfully applies new technologies or identifies additional behind-pipe zones (different productive zones within existing producing well bores) or secondary recovery reserves.

Drilling for oil and natural gas invariably involves unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient reserves to return a profit after deducting drilling, completion, operating and other costs. In addition, wells that are profitable may not achieve a targeted rate of return. The Company relies on third-party operators’ interpretation of seismic data and other advanced technologies in identifying prospects and in conducting exploration and development activities. Nevertheless, prior to drilling a well, the seismic data and other technologies used do not allow operators to know conclusively whether oil, NGL or natural gas is present in commercial quantities.

Cost factors can adversely affect the economics of any project, and the eventual cost of drilling, completing and operating a well is controlled by well operators and existing market

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conditions. Further, drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

 

unexpected drilling conditions;

 

title problems;

 

pressure or irregularities in formations;

 

equipment failures or accidents;

 

fires, explosions, blowouts and surface cratering;

 

lack of availability to market production via pipelines or other transportation;

 

adverse weather conditions;

 

environmental hazards or liabilities;

 

lack of water disposal facilities;

 

governmental regulations;

 

cost and availability of drilling rigs, equipment and services; and

 

expected sales price to be received for oil, NGL or natural gas produced from the wells.

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold properties, which could result in unforeseen operating difficulties. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

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No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and cash available for distribution. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for distribution.

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per share. Any acquisition involves potential risks, including, among other things:

 

the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses and costs;

 

a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;

 

a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

 

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

 

mistaken assumptions about the overall cost of equity or debt;

 

our ability to obtain satisfactory title to the assets we acquire;

 

an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

 

the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

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It is not possible to measure underground accumulations of oil, NGL and natural gas with precision. Oil, NGL and natural gas reserve engineering requires subjective estimates of underground accumulations of oil, NGL and natural gas using assumptions concerning future prices of these commodities, future production levels and operating and development costs. In estimating our reserves, we and our Independent Consulting Petroleum Engineering Firm (DeGolyer and MacNaughton of Dallas, Texas) must make various assumptions with respect to many matters that may prove to be incorrect, including:

 

future oil, NGL and natural gas prices;

 

unexpected complications from offset well development;

 

production rates;

 

reservoir pressures, decline rates, drainage areas and reservoir limits;

 

interpretation of subsurface conditions including geological and geophysical data;

 

potential for water encroachment or mechanical failures;

 

levels and timing of capital expenditures, lease operating expenses, production taxes and income taxes, and availability of funds for such expenditures; and

 

effects of government regulation.

If any of these assumptions prove to be incorrect, our estimates of reserves, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

Our standardized measure of oil and natural gas reserves is calculated using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-month period prior to September 30. These prices and the operating costs in effect as of the date of estimation are held flat over the life of the properties. Production and income tax expenses are deducted from this calculation of future estimated development, with the result discounted at 10% per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.

The reserve estimates made for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy records. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures. Further, our lack of knowledge of all individual well information known to the well operators such as incomplete well stimulation efforts, restricted production rates for various reasons and up-to-date well production data, etc. may cause differences in our reserve estimates.

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Because PUD reserves, under SEC reporting rules, may only be recorded if the wells they relate to are scheduled to be drilled within five years of the date of recording, the removal of PUD reserves that are not developed within this five-year period may be required. Removals of this nature may significantly reduce the quantity and present value of the Company’s oil, NGL and natural gas reserves. Please read Item 2 – “Properties – Proved Reserves” and Note 13 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data.”

Since forward-looking prices and costs are not used to estimate discounted future net cash flows from our estimated proved reserves, the standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil, NGL and natural gas reserves.

The timing of the development and production on our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor used when calculating discounted future net cash flows, in compliance with the FASB statement on oil and natural gas producing activities disclosures, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company, or the oil and natural gas industry in general.

Significant capital expenditures are required to replace our reserves and conduct our business.

Historically, the Company funded exploration, development and production activities primarily through cash flows from operations and acquisitions through borrowings under its credit facility. The timing and amount of capital necessary to carry out these activities can vary significantly as a result of product price fluctuations, property acquisitions, drilling results and the availability of drilling rigs, equipment, well services and transportation capacity.

Cash flows from operations and access to capital are subject to a number of variables, including the Company’s:

 

amount of proved reserves;

 

volume of oil, NGL and natural gas produced;

 

received prices for oil, NGL and natural gas sold;

 

ability to acquire and produce new reserves; and

 

ability to obtain financing.

We may have limited ability to obtain the capital required to sustain our operations at current levels if our borrowing base under our credit facility is lowered as a result of decreased revenues, lower product prices, declines in reserves or for other reasons. Failure to sustain operations at current levels could have a material adverse effect on our financial condition, cash flow and results of operations.

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Debt level and interest rates may adversely affect our business.

The Company has a credit facility with a group of banks headed by Bank of Oklahoma (BOK), which consists of a revolving loan of $200,000,000. As of September 30, 2019, the Company had a balance of $35,425,000 drawn on the facility. The facility has a current borrowing base of $70,000,000, which is secured by certain of the Company’s properties and contains certain restrictive covenants.

Should the Company incur additional indebtedness under its credit facility to fund capital projects or for other reasons, there is risk of it adversely affecting our business operations as follows:

 

cash flows from operating activities required to service indebtedness may not be available for other purposes;

 

covenants contained in the Company’s borrowing agreement may limit our ability to borrow additional funds, pay dividends and make certain investments;

 

any limitation on the borrowing of additional funds may affect our ability to fund capital projects and may also affect how we will be able to react to economic and industry changes;

 

a significant increase in the interest rate on our credit facility will limit funds available for other purposes; and

 

changes in prevailing interest rates may affect the Company’s capability to meet its interest payments, as its credit facility bears interest at floating rates.

The borrowing base of our corporate revolving bank credit facility is subject to periodic redetermination and is based in part on oil, NGL and natural gas prices. A lowering of our borrowing base because of lower oil, NGL or natural gas prices, or for other reasons, could require us to repay indebtedness in excess of the newly established borrowing base, or we might need to further secure the debt with additional collateral. Our ability to meet any debt obligations depends on our future performance. General business, economic, financial and product pricing conditions, along with other factors, affect our future performance, and many of these factors are beyond our control. In addition, our failure to comply with the restrictive covenants relating to our credit facility could result in a default, which might adversely affect our business, financial condition, results of operations and cash flows.

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We may incur losses as a result of title defects in the properties we own.

Consistent with industry practice, we do not have current abstracts or title opinions on all of our mineral acreage and, therefore, cannot be certain that we have unencumbered title to all of these properties. Our failure to cure any title defects that may exist may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we may suffer a financial loss.

Competition in the oil and natural gas industry is intense, and most of our competitors have greater financial and other resources than we do.

We compete in the highly competitive areas of oil and natural gas acquisition, development, exploration and production. We face intense competition from both major and independent oil and natural gas companies to acquire desirable producing properties, new properties for future exploration and human resource expertise necessary to effectively develop properties. We also face similar competition in obtaining sufficient capital to maintain or grow production.

A substantial number of our competitors have financial and other resources significantly greater than ours, and some of them are fully integrated oil and natural gas companies. These companies are able to pay more for development prospects and productive oil and natural gas properties and are able to define, evaluate, bid for, purchase and subsequently drill a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional quality properties in the future will depend upon our ability to successfully evaluate, select and acquire suitable properties with reputable operators in this highly competitive environment.

We may be subject to information technology system failures, network disruptions, cyber-attacks or other breaches in data security.

The oil and natural gas industry in general has become increasingly dependent upon digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We use digital technology to estimate quantities of oil, NGL and natural gas reserves, process and record financial data and communicate with our employees and third parties. Power, telecommunication or other system failures due to hardware or software malfunctions, computer viruses, vandalism, terrorism, natural disasters, fire, human error or by other means could significantly affect the Company’s ability to conduct its business. Though we have implemented complex network security measures, stringent internal controls and maintain offsite backup of all crucial electronic data, there cannot be absolute assurance that a form of system failure or data security breach will not have a material adverse effect on our financial condition and operations results. For instance, unauthorized access to our reserves information or other proprietary or commercially sensitive information could lead to data corruption, communication interruption or other disruptions in our operations or planned

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business transactions, any of which could have a material adverse impact on our results of operations. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

The Company’s derivative activities may reduce the cash flow received for oil and natural gas sales.

In order to manage exposure to price volatility on our oil and natural gas production, we currently, and may in the future, enter into oil and natural gas derivative contracts for a portion of our expected production. Oil and natural gas price derivatives may limit the cash flow we actually realize and therefore reduce the Company’s ability to fund future projects. None of our oil and natural gas price derivative contracts are designated as hedges for accounting purposes; therefore, all changes in fair value of derivative contracts are reflected in earnings. Accordingly, these fair values may vary significantly from period to period, materially affecting reported earnings. In addition, this type of derivative contract can limit the benefit we would receive from increases in the prices for oil and natural gas. The fair value of our oil and natural gas derivative instruments outstanding as of September 30, 2019, was a net asset of $2,494,144.

There is risk associated with our derivative contracts that involves the possibility that counterparties may be unable to satisfy contractual obligations to us. If any counterparty to our derivative instruments were to default or seek bankruptcy protection, it could subject a larger percentage of our future oil and natural gas production to commodity price changes and could have a negative effect on our ability to fund future projects.

Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding derivative contracts.

Future legislative or regulatory changes may result in increased costs and decreased revenues, cash flows and liquidity.

Companies that operate wells in which Panhandle owns a working interest are subject to extensive federal, state and local regulation. Panhandle, as a working interest owner, is therefore indirectly subject to these same regulations. New or changed laws and regulations such as those described below could have a material adverse effect on our business.

Federal Income Taxation

We are subject to U.S. federal income tax, as well as income or capital-based taxes in various states, and our operating cash flow is sensitive to the amount of income taxes we must pay. Income taxes are assessed on our revenue after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow.

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Congress passed legislation in December 2017, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Reform Legislation”), that significantly affects U.S. tax law. The Tax Reform Legislation contains a number of changes to the manner in which the U.S. imposes income tax on multinational corporations. Although some changes should be positive, such as a permanent reduction to the corporate income tax rate, the repeal of the corporate alternative minimum tax, a temporary increase in the amount of bonus depreciation available for qualified property placed into service between September 27, 2017, and December 31, 2022, and other changes may negatively affect the Company. These provisions include, for example, significant additional limitations on the deductibility of interest expense and net operating losses and the repeal of the domestic production activity deduction. In addition, compliance with the Tax Reform Legislation and ensuing regulations will require complex computations and accumulation of information not previously required or regularly produced.

Further revisions to U.S. tax law, such as a reversal of the corporate income tax rate reduction, the repeal of the percentage depletion allowance, the repeal of expensing for intangible drilling costs or the repeal of enhanced bonus depreciation, could have a materially adverse effect on our business. Moreover, the U.S. Department of Treasury has broad authority to issue regulations and interpretative guidance that may significantly impact how we apply U.S. tax law, with a corresponding impact on the results of our operations for the periods affected.

Oklahoma Taxation

Oklahoma imposes a gross production tax, or severance tax, on the value of oil, NGL and natural gas produced within the state. Under recent changes to Oklahoma law, the gross production tax rate on the first three years of a horizontal well’s production was increased from 2.2% to 5.2%, effective July 1, 2018. This increase in tax will likely decrease the profitability of newer horizontal wells producing oil, NGL and natural gas in Oklahoma, including wells in which the Company owns an interest.

Hydraulic Fracturing and Water Disposal

The vast majority of oil and natural gas wells drilled in recent years have been, and future wells are expected to be, hydraulically fractured as a part of the process of completing the wells and putting them on production. This is true of the wells drilled in which the Company owns an interest. Hydraulic fracturing is a process that involves pumping water, sand and additives at high pressure into rock formations to stimulate oil and natural gas production. In developing plays where hydraulic fracturing, which requires large volumes of water, is necessary for successful development, the demand for water may exceed the supply. A lack of readily available water or a significant increase in the cost of water could cause delays or increased completion costs.

In addition to water, hydraulic fracturing fluid contains chemical additives designed to optimize production. Well operators are being required in certain states to disclose the components of these additives. Additional states and the federal government

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may follow with similar requirements or may restrict the use of certain additives. This could result in more costly or less effective development of wells.

Once a well has been hydraulically fractured, the fluid produced from the fractured wells must be either treated for reuse or disposed of by injecting the fluid into disposal wells. Injection well disposal processes have been, and continue to be, studied to determine the extent of correlation between injection well disposal and the occurrence of earthquakes. Certain studies have concluded there is a correlation, and this has resulted in the cessation of or the reduction of injection rates in certain water disposal wells, especially in northern Oklahoma.

Efforts to regulate hydraulic fracturing and fluid disposal continue at the local, state and federal level. New regulations are being considered, including limiting water withdrawals and usage, limiting water disposition, restricting which additives may be used, implementing statewide hydraulic fracturing moratoriums and temporary or permanent bans in certain environmentally sensitive areas. Public sentiment against hydraulic fracturing and fluid disposal and shale production could result in more stringent permitting and compliance requirements. Consequences of these actions could potentially increase capital, compliance and operating costs significantly, as well as delay or halt the further development of oil and gas reserves on the Company’s properties.

Any of the above factors could have a material adverse effect on our financial position, results of operations or cash flows.

Climate Change

Certain studies have suggested that emission of certain gases, commonly referred to as “greenhouse gases,” may be impacting the earth's climate. Methane, the primary component of natural gas, and carbon dioxide, a byproduct of burning oil and natural gas, are examples of greenhouse gases. Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as oil and gas production equipment and operations.

Legislation to regulate greenhouse gas emissions has periodically been introduced in the U.S. Congress and such legislation may be proposed in the future. In addition, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, in preparing an agreement which set greenhouse gas emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. To help achieve these reductions, federal agencies addressed climate change through a variety of administrative actions. The U.S. Environmental Protection Agency (the “EPA”) issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. However, on June 1, 2017, the President of the United States announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations to either reenter the Paris Agreement on different terms or

21


 

establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement, or a separately negotiated agreement are unclear at this time.

The direction of future U.S. climate change regulation is difficult to predict given the current uncertainties surrounding the policies of the Trump Administration. The EPA may or may not continue developing regulations to reduce greenhouse gas emissions from the oil and natural gas industry. Even if federal efforts in this area slow, states may continue pursuing climate regulations. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require our operators to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes and reduce demand.

Seismic Activity

Earthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation that could lead to operational delays, increase operating and compliance costs or otherwise adversely affect operations.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on us and our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the CFTC (the United States Commodity Futures Trading Commission) and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market including swap clearing and trade execution requirements. New or modified rules, regulations or requirements may increase the cost and availability to the counterparties of our hedging and swap positions which they can make available to us, as applicable, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to separate entities which may not be as creditworthy as the current counterparties. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.

While many rules and regulations have been promulgated and are already in effect, other rules and regulations remain to be finalized or effectuated and, therefore, the impact of those rules and regulations on us is uncertain at this time. The Dodd-Frank Act, and the rules promulgated thereunder, could (i) significantly increase the cost, or decrease the liquidity, of energy-related derivatives that we use to hedge against commodity price fluctuations (including requirements to post collateral), (ii) materially alter the terms of derivative contracts, (iii) reduce the availability of derivatives to protect against risks we encounter and (iv) increase our exposure to less creditworthy counterparties.

22


 

Risks Related to our Third-Party Operators

The Company cannot control activities on its properties.

The Company does not operate any of the properties in which it has an interest and has very limited ability to exercise influence over the third-party operators of these properties. Our dependence on the third-party operators of our properties, and on the cooperation of other working interest owners in these properties, could negatively affect the following:

 

the Company’s return on capital used in drilling or property acquisition;

 

the Company’s production and reserve growth rates;

 

capital required to workover or recomplete wells;

 

success and timing of drilling, development and exploitation activities on the Company’s properties;

 

compliance with environmental, safety and other regulations;

 

lease operating expenses; and

 

plugging and abandonment costs, including well-site restorations.

Dependency on each operator’s judgment, expertise and financial resources could result in unexpected future costs, lost revenues and/or capital restrictions, to the extent they would cumulatively have a material adverse effect on the Company’s financial position and results of operations.

The oil and natural gas drilling and producing operations of our third-party operators involve various risks.

Because we do not operate our properties, our business relies heavily upon our third-party operators and their operational effectiveness. Through our third-party operators, we are subject to all the risks normally incident to the operation and development of oil and natural gas properties, including:

 

well blowouts, cratering, explosions and human related accidents;

 

mechanical, equipment and pipe failures;

 

adverse weather conditions, earthquakes and other natural disasters;

 

civil disturbances and terrorist activities;

 

oil, NGL and natural gas price reductions;

23


 

 

environmental risks stemming from the use, production, handling and disposal of water, waste materials, hydrocarbons and other substances into the air, soil or water;

 

title problems;

 

limited availability of financing;

 

marketing related infrastructure, transportation and processing limitations; and

 

regulatory compliance issues.

As a non-operator, we are also dependent on third-party operators and the contractors they hire for operational safety, environmental safety and compliance with regulations of governmental authorities.

The Company maintains insurance against many potential losses or liabilities arising from well operations in accordance with customary industry practices and in amounts believed by management to be prudent. However, this insurance does not protect the Company against all risks. For example, the Company does not maintain insurance for business interruption, acts of war or terrorism. Additionally, pollution and environmental risks generally are not fully insurable. These risks could give rise to significant uninsured costs that might have a material adverse effect on the Company’s business condition and financial results.

We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.

A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.

24


 

Shortages of oilfield equipment, services, qualified personnel and resulting cost increases could adversely affect results of operations.

The demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, NGL and natural gas prices, resulting in periodic shortages. When demand for rigs and equipment increases due to an increase in the number of wells being drilled, there have been shortages of drilling rigs, hydraulic fracturing equipment and personnel and other oilfield equipment. Higher oil, NGL and natural gas prices generally stimulate increased demand for, and result in increased prices of, drilling rigs, crews and associated supplies, equipment and services. These shortages or price increases could negatively affect the ability to drill wells and conduct ordinary operations by the operators of the Company’s wells, resulting in an adverse effect on the Company’s financial condition, cash flow and operating results.

The marketability of oil and natural gas production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators’ control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.

The marketability of our or our operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, the shipment of our or our operators’ oil and natural gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations and cash distributions to stockholders. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil production, transportation and pipeline safety—as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

Risks Related to the Oil and Gas Industry

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, financial condition and cash available for distribution.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit in the European, Asian and the U.S. markets contribute to

25


 

economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, NGL and natural gas, volatility in consumer confidence and job markets, may result in an economic slowdown or recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which oil, NGL and natural gas from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Risks Related to an Investment in our Common Stock

The issuance of additional shares of our common stock could cause the market price of our common stock to decline and may result in dilution to our existing stockholders.

The Company filed a shelf registration statement, which was declared effective on November 15, 2017, that allows us to issue up to $75 million in securities including common stock, preferred stock, debt, warrants and units. The shelf registration statement is intended to provide the Company with increased financial flexibility and more efficient access to the capital markets.

We cannot predict the effect, if any, that market sales of these securities or the availability of the securities will have on the market price of our common stock prevailing from time to time. Substantial sales of shares of our common stock or other securities in the public market, or the perception that those sales could occur, may cause the market price of our common stock to decline. Such a decrease in our share price could in turn impair our ability to raise capital through the sale of additional equity securities. In addition, any such decline may make it more difficult for stockholders to sell shares of our common stock at prices they deem acceptable.

We are currently authorized to issue an aggregate of 24,000,000 shares of common stock of which 16,339,255 shares were issued and outstanding on December 1, 2019. Future issuances of our common stock, or other securities convertible into our common stock, may result in significant dilution to our existing stockholders. Significant dilution would reduce the proportionate ownership and voting power held by our existing stockholders.

26


 

We may reduce or suspend our dividend in the future.

We have paid a quarterly dividend for many years. Our most recent quarterly dividend was $0.04 per share, and we have paid the same quarterly dividend for the past two years. In the future, our Board may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position the Company for long‑term success. The declaration and amount of future dividends is at the discretion of our Board and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness. In addition, our ability to pay dividends may be limited by agreements governing our indebtedness now or in the future. Although we do not currently have plans to reduce or suspend our dividend, there can be no assurance that we will not reduce our dividend or that we will continue to pay a dividend in the future.

ITEM 1B.

Staff Comments

None

ITEM 2.

Properties

General Background

Panhandle is focused on perpetual oil and natural gas mineral ownership in resource plays in the United States. As part of our evolution as a company, we also own interests in leasehold acreage and non-operated working interests in oil and natural gas properties.

At September 30, 2019, Panhandle’s principal properties consisted of (i) perpetual ownership of 258,231 net mineral acres, held principally in Oklahoma, North Dakota, Texas, Arkansas and New Mexico; (ii) leases on 17,199 net acres primarily in Oklahoma; and (iii) working interests, royalty interests or both in 6,496 producing oil and natural gas wells and 120 wells in the process of being drilled or completed.

Management’s Business Strategy Related to Properties

During fiscal 2019, the Company made the strategic decision to focus on perpetual oil and natural gas mineral ownership and growth through mineral acquisitions and the development of its significant mineral acreage inventory in its core areas of focus. In accordance with this strategy, we will no longer participate in new development on our mineral or leasehold acreage with a cost-bearing working interest. The Company believes that its strategy to focus on mineral ownership is the best path to giving the Company’s stockholders the greatest risk-weighted returns on their investments going forward.

Our goal is to increase stockholder value through the management of our fee mineral and leasehold assets as a portfolio. We plan to grow our mineral fee holdings by acquiring mineral acreage, in the cores of resource plays with substantial undeveloped opportunities, that meets or exceeds our corporate return threshold. We also plan to aggressively lease our mineral holdings.

27


 

We have an active program in place focused on leasing open acreage to generate additional lease bonus revenue and future royalty revenue.

Title to Properties

Consistent with industry practice, the Company does not have current abstracts or title opinions on all of its mineral acreage and, therefore, cannot be certain that it has unencumbered title to all of its properties. In recent years, a few insignificant challenges have been made against the Company’s fee title to its acreage.

Acreage

Mineral Interests Owned

The following table of mineral interests owned reflects, in each respective state, the number of (i) net and gross acres owned by the Company, (ii) net and gross producing acres owned by the Company, (iii) net and gross acres leased to others by the Company and (iv) net and gross acres open (unleased) as of September 30, 2019.

 

State

 

Net Acres

 

 

Gross Acres

 

 

Net Acres Producing

(1)

 

 

Gross

Acres

Producing

(1)

 

 

Net Acres

Leased to

Others (2)

 

 

Gross

Acres

Leased to

Others (2)

 

 

Net Acres

Open

(3)

 

 

Gross Acres

Open

(3)

 

Arkansas

 

 

11,965

 

 

 

51,391

 

 

 

7,167

 

 

 

27,026

 

 

 

-

 

 

 

-

 

 

 

4,798

 

 

 

24,365

 

Colorado

 

 

8,217

 

 

 

39,081

 

 

 

-

 

 

 

-

 

 

 

8

 

 

 

80

 

 

 

8,209

 

 

 

39,001

 

Florida

 

 

3,665

 

 

 

7,878

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

3,665

 

 

 

7,878

 

Kansas

 

 

3,102

 

 

 

11,856

 

 

 

164

 

 

 

1,240

 

 

 

-

 

 

 

-

 

 

 

2,938

 

 

 

10,616

 

Montana

 

 

1,008

 

 

 

17,948

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

1,008

 

 

 

17,948

 

New Mexico

 

 

57,169

 

 

 

173,445

 

 

 

1,336

 

 

 

6,808

 

 

 

190

 

 

 

391

 

 

 

55,643

 

 

 

166,246

 

North Dakota

 

 

14,303

 

 

 

78,103

 

 

 

2,773

 

 

 

14,490

 

 

 

-

 

 

 

-

 

 

 

11,530

 

 

 

63,613

 

Oklahoma

 

 

114,377

 

 

 

960,315

 

 

 

43,889

 

 

 

349,495

 

 

 

7,625

 

 

 

50,313

 

 

 

62,863

 

 

 

560,507

 

South Dakota

 

 

1,825

 

 

 

9,300

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

1,825

 

 

 

9,300

 

Texas

 

 

42,408

 

 

 

355,978

 

 

 

5,269

 

 

 

53,265

 

 

 

5,567

 

 

 

42,162

 

 

 

31,572

 

 

 

260,551

 

Other

 

 

192

 

 

 

3,262

 

 

 

165

 

 

 

3,000

 

 

 

-

 

 

 

-

 

 

 

27

 

 

 

262

 

Total:

 

 

258,231

 

 

 

1,708,557

 

 

 

60,763

 

 

 

455,324

 

 

 

13,390

 

 

 

92,946

 

 

 

184,078

 

 

 

1,160,287

 

 

(1)

“Producing” represents the mineral acres in which Panhandle owns a royalty or working interest in a producing well.

(2)

“Leased” represents the mineral acres owned by Panhandle that are leased to third parties but not producing.

(3)

“Open” represents mineral acres owned by Panhandle that are not leased or in production.

28


 

Leases

The following table reflects the Company’s net mineral acres leased from others, lease expiration dates, and net leased acres held by production as of September 30, 2019.

 

 

 

 

 

 

 

Net Acres Expiring

 

 

 

 

 

State

 

Net

Acres

 

 

2020

 

 

2021

 

 

2022

 

 

2023

 

 

2024

 

 

Net Acres

Held by

Production

 

Arkansas

 

 

2,159

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

2,159

 

Oklahoma

 

 

11,608

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

11,608

 

Texas

 

 

2,349

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

2,349

 

Other

 

 

1,083

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

1,083

 

TOTAL

 

 

17,199

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

17,199

 

 

Proved Reserves

 

Summary of Proved Reserves

The following table summarizes estimates of proved reserves of oil, NGL and natural gas held by Panhandle as of September 30, 2019, compared to the two preceding year ends, using prices and costs under existing economic conditions. Proved reserves are located onshore within the contiguous United States and are principally made up of small interests in 6,496 wells, which are predominately located in the Mid-Continent region. Other than this report, the Company’s reserve estimates are not filed with any other federal agency.

Summary of Proved Oil and Natural Gas Reserves

 

 

 

Oil

 

 

NGL

 

 

Natural Gas

 

 

Total Proved

 

 

 

(Bbl)

 

 

(Bbl)

 

 

(Mcf)

 

 

(Mcfe)

 

Net Proved Developed Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2019

 

 

1,863,096

 

 

 

1,747,242

 

 

 

67,713,193

 

 

 

89,375,221

 

September 30, 2018

 

 

2,334,587

 

 

 

2,085,706

 

 

 

83,151,954

 

 

 

109,673,712

 

September 30, 2017

 

 

2,201,528

 

 

 

1,768,425

 

 

 

87,861,043

 

 

 

111,680,761

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Proved Undeveloped Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2019

 

 

516,994

 

 

 

226,038

 

 

 

12,560,713

 

 

 

17,018,905

 

September 30, 2018

 

 

3,649,835

 

 

 

848,484

 

 

 

36,910,082

 

 

 

63,899,996

 

September 30, 2017

 

 

3,308,139

 

 

 

616,274

 

 

 

33,334,077

 

 

 

56,880,555

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Total Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2019

 

 

2,380,090

 

 

 

1,973,280

 

 

 

80,273,906

 

 

 

106,394,126

 

September 30, 2018

 

 

5,984,422

 

 

 

2,934,190

 

 

 

120,062,036

 

 

 

173,573,708

 

September 30, 2017

 

 

5,509,667

 

 

 

2,384,699

 

 

 

121,195,120

 

 

 

168,561,316

 

 

29


 

Exploration and development of our oil and natural gas properties is conducted by oil and natural gas exploration and production companies, primarily larger independent operating companies. We do not operate any of our oil and natural gas properties.

 

For the year ended September 30, 2019, our net total proved reserves decreased by approximately 67.2 Bcfe, as compared to September 30, 2018. The decrease in total proved reserves from 2018 to 2019 is attributable to a combination of the following factors:

 

Negative pricing revisions of 4.4 Bcfe (comprised of proved developed revisions of 4.3 Bcfe and PUD revisions of 0.1 Bcfe), which primarily resulted from oil and natural gas wells reaching their economic limits earlier than was projected in 2018 due to lower oil prices and higher natural gas price deducts in 2019 relative to 2018.

 

Negative revisions of 56.2 Bcfe, which included (i) proved undeveloped negative revisions of 48.2 Bcfe, primarily resulting from the Company’s implementation of its new strategy of focusing on perpetual mineral ownership and not participating with a working interest in future drilling programs, which resulted in the removal of undeveloped leasehold wells (including wells in the Eagle Ford Shale) and lowering the net revenue interest on previously planned working interest wells on our mineral acreage to a royalty revenue interest only and (ii) proved developed revisions of negative 8.0 Bcfe, principally due to lower performance of our high-interest Woodford natural gas wells drilled in 2017 in the Arkoma Stack and, to a lesser extent, lower performance of the Fayetteville Shale natural gas properties in Arkansas.

 

Proved developed reserve extensions, discoveries and other additions of 2.1 Bcfe principally resulting from: (i) the Company’s royalty interest ownership in the ongoing development of unconventional oil, NGL and natural gas utilizing extended horizontal drilling in the Woodford Shale in the STACK, SCOOP and Arkoma Stack in Oklahoma; (ii) the Company’s royalty interest ownership in the ongoing development of unconventional oil, NGL and natural gas utilizing horizontal drilling in the STACK Meramec play in the Anadarko Basin in western Oklahoma; and (iii) the Company’s royalty interest ownership in ongoing development of conventional and unconventional oil, NGL and natural gas utilizing horizontal drilling in the Permian Basin.

 

The addition of 4.7 Bcfe of PUD reserves within the Company’s active drilling program areas of (i) the STACK Meramec in western Oklahoma, (ii) the SCOOP Woodford Shale in western Oklahoma, (iii) the Woodford Shale in the Arkoma Stack in southeastern Oklahoma, (iv) the Marmaton in Ellis County, Oklahoma, and (v) the Yeso in Eddy County, New Mexico.

 

The acquisition of 0.8 Bcfe, predominately in the active drilling program of the Bakken in North Dakota, of which 0.5 Bcfe were proved developed and 0.3 Bcfe were proved undeveloped.

30


 

 

The sale of 3.8 Bcfe, predominately in the Permian Basin in Texas and New Mexico, of which 2.2 Bcfe were proved developed and 1.6 Bcfe were proved undeveloped.

 

Production of 10.4 Bcfe from the Company’s oil and natural gas properties.

Proved Undeveloped Reserves

The following details the changes in proved undeveloped reserves for 2019 (Mcfe):

 

Beginning proved undeveloped reserves

 

 

63,899,996

 

Proved undeveloped reserves transferred to proved developed

 

 

(1,763,402

)

Revisions

 

 

(48,404,716

)

Extensions and discoveries

 

 

4,679,986

 

Sales

 

 

(1,648,780

)

Purchases

 

 

255,821

 

Ending proved undeveloped reserves

 

 

17,018,905

 

 

 

For the fiscal year ending September 30, 2019, our beginning PUD reserves were 63.9 Bcfe. In 2019, a total of 1.8 Bcfe (3% of the beginning balance) was transferred to proved developed. The 48.4 Bcfe (76% of the beginning balance) of negative revisions to PUD reserves were pricing revisions of 0.2 Bcfe and a revision of 48.2 Bcfe, predominately resulting from the removal of oil, NGL and natural gas reserves associated with our working interest in Eagle Ford wells and working interests in wells in the STACK, SCOOP and Arkoma Stack plays, consistent with the Company implementing the strategy to no longer participate with working interests moving forward.

 

We anticipate that all the Company’s current PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves, which are no longer projected to be drilled within five years from the date they were added to PUD reserves, will be removed as revisions at the time that determination is made. In the event that there are undrilled PUD locations at the end of the five-year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions. The Company added 4.7 Bcfe of PUD reserves in 2019 within the active drilling program areas of (i) the SCOOP Woodford Shale in western Oklahoma, (ii) the Anadarko Basin STACK Meramec in western Oklahoma, (iii) the Marmaton in Ellis County, Oklahoma, (iv) the Arkoma Stack in eastern Oklahoma and (v) the Yeso in Eddy County, New Mexico. These additions result from continuing development and additional well performance data in each of the referenced plays. Additionally, the Company purchased 0.3 Bcfe in the Bakken play in North Dakota and sold 1.6 Bcfe, predominately in the Permian Basin in Texas and New Mexico.

Estimated Future Net Cash Flows

Set forth below are estimated future net cash flows with respect to Panhandle’s net proved reserves (based on the estimated units set forth above in Proved Reserves) for each of the years indicated, and the present value of such estimated future net cash flows, computed by applying a 10% discount factor as required by SEC rules and regulations. The Company follows

31


 

the SEC rule, Modernization of Oil and Gas Reporting Requirements. In accordance with the SEC rule, the estimated future net cash flows were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-month period prior to September 30 held flat over the life of the properties and applied to future production of proved reserves less estimated future development and production expenditures for these reserves. The amounts presented are net of operating costs and production taxes levied by the respective states. Prices used for determining future cash flows from oil, NGL and natural gas as of September 30, 2019, 2018 and 2017, were as follows: in 2019, $54.40/Bbl for oil, $19.30/Bbl for NGL and $2.48/Mcf for natural gas; in 2018, $62.86/Bbl for oil, $26.13/Bbl for NGL and $2.56/Mcf for natural gas; and in 2017, $46.31/Bbl for oil, $17.55/Bbl for NGL and $2.81/Mcf for natural gas. These future net cash flows based on SEC pricing rules should not be construed as the fair market value of the Company’s reserves. A market value determination would need to include many additional factors, including anticipated oil, NGL and natural gas price and production cost increases or decreases, which could affect the economic life of the properties.

 

Estimated Future Net Cash Flows

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9/30/2019

 

 

9/30/2018

 

 

9/30/2017

 

Proved Developed

 

$

161,943,514

 

 

$

236,887,976

 

 

$

206,878,778

 

Proved Undeveloped

 

 

48,900,497

 

 

 

174,078,883

 

 

 

81,303,463

 

Income Tax Expense

 

 

(47,788,416

)

 

 

(95,872,182

)

 

 

(102,193,819

)

Total Proved

 

$

163,055,595

 

 

$

315,094,677

 

 

$

185,988,422

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10% Discounted Present Value of Estimated Future Net Cash Flows

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9/30/2019

 

 

9/30/2018

 

 

9/30/2017

 

Proved Developed

 

$

86,814,212

 

 

$

125,915,804

 

 

$

112,276,166

 

Proved Undeveloped

 

 

23,581,427

 

 

 

78,657,354

 

 

 

13,746,585

 

Income Tax Expense

 

 

(24,834,110

)

 

 

(48,247,304

)

 

 

(45,190,176

)

Total Proved

 

$

85,561,529

 

 

$

156,325,854

 

 

$

80,832,575

 

 

Evaluation and Review of Reserves

The determination of reserve estimates is a function of testing and evaluating the production and development of oil and natural gas reservoirs in order to establish a production decline curve. The established production decline curves, in conjunction with oil and natural gas prices, development costs, production taxes and operating expenses, are used to estimate oil and natural gas reserve quantities and associated future net cash flows. As information is processed regarding the development of individual reservoirs, and as market conditions change, estimated reserve quantities and future net cash flows will change over time as well. Estimated reserve quantities and future net cash flows are affected by changes in product prices. These prices have varied substantially in recent years and are expected to vary substantially from current pricing in the future.

32


 

The Company follows the SEC’s modernized oil and natural gas reporting rules, which were effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. See Note 13 to the financial statements in Item 8 – “Financial Statements and Supplementary Data” for disclosures regarding our oil and natural gas reserves.

Under the SEC rules, oil and natural gas reserves are those quantities of oil and natural 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. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves, which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection), are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor, compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserve estimate, if the extraction is by means not involving a well.

Undeveloped oil and natural gas reserves are reserves of any category 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. Reserves on undrilled acreage are limited to

33


 

those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, prepared the Company’s oil, NGL and natural gas reserves estimates as of September 30, 2019, 2018 and 2017 (see Exhibits 23.2 and 99). Within DeGolyer and MacNaughton, the technical person primarily responsible for preparing the estimates set forth in the Report of DeGolyer and MacNaughton dated October 7, 2019, filed as Exhibit 99 to this Annual Report on Form 10-K, was Gregory K. Graves. Mr. Graves has a Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin and is a Registered Professional Engineer in the state of Texas. He is a member or the Society of Petroleum Evaluation Engineers and has over 35 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Graves meets or exceeds 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 and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

All of the reserve estimates are reviewed and approved by our Vice President of Operations, Freda Webb. Ms. Webb holds a Bachelor of Science degree in Mechanical Engineering from the University of Oklahoma, a Master of Science degree in Petroleum Engineering from the University of Southern California and a Professional Engineering License in Petroleum Engineering in the State of Oklahoma. Ms. Webb has more than 36 years of experience in the oil and gas industry. She is an active member of the Society of Petroleum Engineers (SPE).

Our Vice President of Operations and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information (such as ownership interest, oil and gas production, well test data, commodity prices, operating costs, handling fees, and development costs) for all properties to our Independent Consulting Petroleum Engineers. Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions. The Company’s net proved oil, NGL and natural gas reserves (including certain undeveloped reserves described above) are located onshore in the contiguous United States. All studies have been prepared in accordance with regulations prescribed by the SEC. The reserve estimates were based on economic and operating conditions existing at September 30, 2019, 2018 and 2017. Since the determination and valuation of proved reserves is a function of testing

34


 

and estimation, the reserves presented are expected to change as future information becomes available.

 

Oil, NGL and Natural Gas Production

The following table sets forth the Company’s net production of oil, NGL and natural gas for the fiscal periods indicated.

 

 

 

Year Ended

 

 

Year Ended

 

 

Year Ended

 

 

 

9/30/2019

 

 

9/30/2018

 

 

9/30/2017

 

Bbls - Oil

 

 

329,199

 

 

 

336,565

 

 

 

310,677

 

Bbls - NGL

 

 

216,259

 

 

 

255,176

 

 

 

173,858

 

Mcf - Natural Gas

 

 

7,086,761

 

 

 

8,721,262

 

 

 

8,194,529

 

Mcfe

 

 

10,359,509

 

 

 

12,271,708

 

 

 

11,101,739

 

 

Average Sales Prices and Production Costs

The following tables set forth unit price and cost data for the fiscal periods indicated.

 

 

 

Year Ended

 

 

Year Ended

 

 

Year Ended

 

Average Sales Price

 

9/30/2019

 

 

9/30/2018

 

 

9/30/2017

 

Per Bbl, Oil

 

$

55.07

 

 

$

61.75

 

 

$

46.27

 

Per Bbl, NGL

 

$

17.10

 

 

$

23.14

 

 

$

19.87

 

Per Mcf, Natural Gas

 

$

2.48

 

 

$

2.49

 

 

$

2.70

 

Per Mcfe

 

$

3.80

 

 

$

3.94

 

 

$

3.60

 

 

 

 

Year Ended

 

 

Year Ended

 

 

Year Ended

 

Average Production (lifting) Costs

 

9/30/2019

 

 

9/30/2018

 

 

9/30/2017

 

(Per Mcfe)

 

 

 

 

 

 

 

 

 

 

 

 

Well Operating Costs (1)

 

$

1.21

 

 

$

1.10

 

 

$

1.14

 

Production Taxes (2)

 

 

0.18

 

 

 

0.17

 

 

 

0.14

 

 

 

$