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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 December 31, 2013

 

¨ Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

For the transition period from                      to                     

Commission File Number 33-16820-D

 

 

ARÊTE INDUSTRIES, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Colorado   84-1508638

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer

Identification No.)

 

7260 Osceola Street, Westminster, Colorado   80030
(Address of Principal Executive Offices)   (Zip Code)

(303) 427-8688

(Registrant’s Telephone Number, Including Area Code)

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

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

Name of Exchange on which registered: None

 

 

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  x    No  ¨(1)

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 and posted on its corporate Web site, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in the definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   ¨    Smaller reporting company   x

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

On March 31, 2014, the aggregate market value of the 7,641,552 shares of common stock held by non-affiliates of the Registrant was approximately $2,368,881.

As of March 31, 2014, the Registrant had 12,408,459 shares of common stock issued and outstanding.

Documents Incorporated By Reference - None

 

(1) Explanatory Note: The Company is voluntary filer with the Securities & Exchange Commission but it has filed all Exchange Act reports for the preceding 12 months.

 

 

 


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Arête Industries, Inc.

Index to Form 10-K

 

          Page  
PART I      
Item 1.    Business      4   
Item 1A.    Risk Factors      10   
Item 1B    Unresolved Staff Comments      18   
Item 2.    Properties      19   
Item 3.    Legal Proceedings      20   
Item 4.    Mine Safety Disclosures      20   
PART II      
Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      20   
Item 6.    Selected Financial Data      22   
Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations      23   
Item 7A.    Quantitative and Qualitative Disclosures About Market Risk   
Item 8.    Financial Statements and Supplementary Data.      33   
Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      58   
Item 9-A    Controls and Procedures      58   
Item 9-B    Other Information      58   
PART III      
Item 10.    Directors, Executive Officers and Corporate Governance      59   
Item 11.    Executive Compensation      61   
Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      62   
Item 13.    Certain Relationships and Related Transactions, and Director Independence      63   
Item 14.    Principal Accounting Fees and Services      65   
PART IV      
Item 15.    Exhibits, Financial Statement schedules      67   


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Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in this Annual Report on Form 10-K (and other documents to which it refers) are not statements of historical fact and constitute forward-looking statements within the meaning of the various provisions of the Securities Act of 1933, as amended, which we refer to as the Securities Act, and the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act, including, without limitation, the statements specifically identified as forward-looking statements within this Annual Report on Form 10-K. Many of these statements contain risk factors as well. In addition, certain statements in our future filings with the SEC, in press releases, and in oral and written statements made by or with our approval, which are not statements of historical fact, constitute forward-looking statements within the meaning of the Securities Act and the Exchange Act. Examples of forward-looking statements, include, but are not limited to: (i) projections of capital availability, terms, expenditures, revenues, income or loss, earnings or loss per share, the payment or non-payment of dividends on our common stock and on our convertible preferred stock, capital structure, and other financial items, (ii) statements of our plans and objectives or our management or board of directors including those relating to possible development of our oil and gas properties, (iii) statements of future economic performance and (iv) statements of assumptions underlying such statements. Words such as “believes”, “anticipates”, “expects”, “intends”, “targeted”, “may”, “will” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

 

    our ability to alleviate our significant working capital deficit and continue business as a going concern

 

    changes in production volumes, worldwide demand and commodity prices for oil and natural gas;

 

    changes in estimates of proved reserves;

 

    declines in the values of our oil and natural gas properties resulting in impairments;

 

    the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves;

 

    our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;

 

    risks incident to the drilling and operation of oil and natural gas wells;

 

    future production and development costs;

 

    the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;

 

    the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America;

 

    changes in environmental laws and the regulation and enforcement related to those laws;

 

    the identification of and severity of environmental events and governmental responses to the events;

 

    the effect of oil and natural gas derivatives activities; and

 

    conditions in the capital markets.

Such forward-looking statements speak only as of the date on which such statements are made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made to reflect the occurrence of unanticipated events.

 

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CERTAIN DEFINITIONS

Unless the context in this Annual Report on Form 10-K otherwise requires, the terms the “Company”, “we”, “us”, “our” or “ours” when used herein refers to Arête Industries, Inc., together with its consolidated subsidiary. When the context requires, we refer to these entities separately. We have included below the definitions for certain terms used in this Annual Report on Form 10-K:

Bbl – One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bbls/d or BOPD – barrels per day or barrels of oil per day.

BOE – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Carried interest – A contractual arrangement, usually in a drilling project, whereby all or a portion of the working interest cost participation of the project originator is paid for by another party in exchange for earning an interest in such project.

Completion – The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Compression – A force that tends to shorten or squeeze, decreasing volume or increasing pressure.

DD&A – Depreciation, depletion, amortization and accretion.

Developed acreage – The number of acres which are allotted or assignable to producing wells or wells capable of production.

Development activities – Activities following acquisition or exploration including the drilling and completion of additional wells and the installation of production facilities.

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

Dry hole or well – A well found to be incapable of producing hydrocarbons economically.

Exploitation – The act of making an oil and gas property more profitable, productive or useful.

Exploratory well – A well drilled to find oil or natural gas reserves in an area or to a potential reservoir not classified as proved.

Farm-in or Farm-out – An agreement whereby the owner of a working interest in an oil and natural gas lease assigns or contractually conveys subject to future assignment the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the farmee is required to drill one or more wells in order to earn its interest in the acreage. The farmor usually retains a royalty and/or after payout interest in the lease. The interest received by the farmee is a “farm-in” while the interest transferred by the farmor is a “farm-out.”

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 and/or stratigraphic condition.

GAAP – Generally accepted accounting principles in the United States of America.

Gross acres or gross wells – The total acres or wells, as the case may be, in which a working interest is owned.

Mbtu (Mmbtu) – Used as a standard unit of measurement for natural gas and provides a convenient basis for comparing the energy content of various grades of natural gas and other fuels. One cubic foot of natural gas produces approximately 1,000 BTUs, so 1,000 cubic feet of gas is comparable to 1 Mbtu. Mbtu is often expressed as MMbtu, which is intended to represent a thousand BTUs.

Mcf – One thousand cubic feet.

MmcfOne million cubic feet.

Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.

NGL’s – Natural gas liquids measured in barrels.

NRI or Net Revenue Interests – The share of production after satisfaction of all royalty, oil payments and other non-operating interests.

Plugging and abandonment or P&A – Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface.

PV10 – The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using prices and costs, as prescribed in the SEC rules, as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion, amortization and accretion, or Federal income taxes and discounted using an annual discount rate of 10%. PV10 is considered a Non-GAAP financial measure as defined by the SEC.

Productive well – A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production taxes and lease operating expenses.

 

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Proved developed nonproducing reserves or PDNP – Proved reserves that meet the definition of proved developed reserves (defined below) but are either shut-in or are behind-pipe reserves.

Proved developed producing reserves or PDP – Proved reserves that meet the definition of proved developed reserves (defined below) that are currently able to produce to market.

Proved developed reserves – Proved developed oil and 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 costs of the required equipment is relatively minor compared to the costs of a new well.

Proved reserves – Proved oil and gas reserves are those quantities of oil and 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 estimates. 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.

Proved undeveloped reserves or PUDs – Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. 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

Reasonable certainty – If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical or geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

Re-engineering – a process involving a comprehensive review of the mechanical conditions associated with wells and equipment in producing fields. Our re-engineering practices typically result in a capital expenditure plan, which is implemented over time, to workover (see below) and re-complete wells and modify down-hole artificial lift equipment and surface equipment and facilities. The programs are designed specifically for individual fields to increase and maintain production, reduce down-time and mechanical failures, lower per-unit operating expenses, and therefore, improve field economics.

Reservoir – A permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest – An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

SEC – The U.S. Securities and Exchange Commission.

Secondary recovery – The use of water-flooding or gas injection to maintain formation pressure during primary production and to reduce the rate of decline of the original reservoir drive.

Shut-in reserves – Those reserves expected to be recovered from completion intervals that were open at the time the reserves were estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed. These reserves are included in the PDNP category on the reserve report.

Standardized Measure of Discounted Future Net Cash Flows – A measure of the present value of the estimated future cash flows to be derived from the production and sale of proved oil and gas reserves. Estimated production taxes, estimated operating expenses, estimated future investment costs, and estimated future income taxes are deducted from estimated future cash inflows and discounted at PV 10 to arrive at the standardized measure of discounted future net cash flows. We calculate this measure in accordance with FASB ASC Topic (932) Extractive Activities – Oil and Gas.

Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest or WI – The ownership interest, generally defined in a joint operating agreement, that gives the owner the right to drill, produce and/or conduct operating activities on the property and share in the sale of production, subject to all royalties, overriding royalties and other burdens and obligates the owner of the interest to share in all costs of exploration, development, and production and all risks in connection therewith.

Workover – Major remedial operations on a completed well to restore, maintain or improve the well’s production.

 

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PART 1

Item 1. BUSINESS

Overview

Arête Industries, Inc., a Colorado corporation, is an independent oil and gas company engaged in the acquisition and development of oil and natural gas reserves through a program which includes purchases of reserves, re-engineering, development and exploration activities primarily focused in Wyoming, Kansas, Colorado and Montana.

In September 2006, we acquired a gas gathering system (pipeline and compressor station related assets) in Campbell County, Wyoming. This system was constructed in late 2001 and began operations early in 2002. The system consists of 4.5 miles of 8-inch coated steel pipeline. During the first half of 2011, this pipeline was transporting approximately 900,000 Mcf (thousand cubic feet) of coal bed methane per day and was cash flowing from its operations until June 2011 when the operator shut-in the coal bed methane wells due to the low prices received for the natural gas produced. This system has a current throughput capacity of approximately 4 million cubic feet of gas per day, although the system is currently idle since the related wells are shut-in.

On May 25, 2011, we entered into a purchase and sale agreement and other related agreements and documents with Tucker Family Investments, LLLP; DNR Oil & Gas, Inc. which we refer to as DNR; and Tindall Operating Company, which we refer to as Tindall, and collectively we refer to these parties as the Sellers, for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana, which we refer to collectively as the original purchase and sale agreement. DNR is owned primarily by an officer and director of the Company, Charles B. Davis. The consideration for the purchase was determined by bargaining between management of the Company and Mr. Davis, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price was paid in full on September 29, 2011. The Company may be obligated to make additional payments under the amended purchase and sale agreement if the Company increases its proven producing net oil reserves or net gas reserves by drilling or recompletion on certain of the acquired properties in Colorado and Kansas, then the Company will pay $250,000 for every 20,000 bbls or 150,000 mcf increase respectively. If the Nymex prices for oil and/or gas stay above certain thresholds for more than 60 days, the Company will also be required to pay an additional $250,000 as each threshold is exceeded for more than 60 consecutive days. Cumulative payments under the additional purchase price factor for the Colorado and Kansas properties are limited to $5 million. The Company will also make similar payments to the Sellers if the Company increases reserves in the Wyoming and Montana properties, and the Company will make additional payments under a formula by which Sellers and the Company will share proceeds of sales or production from untapped formations on the properties acquired in Wyoming and Montana. Cumulative payments under the additional purchase price factor for the Wyoming and Montana properties are limited to $20 million. The aggregate of all additional purchase price payments from all factors and all states is capped at $25 million. Due to consideration retained by the related party sellers from sales of properties during 2012 and 2013, and $250,000 of consideration payable in December 2012 and an additional $250,000 of contingent consideration due to sustained increases in oil prices over $100 per barrel, the maximum future consideration has been reduced by approximately $5.8 million to $19.2 million as of December 31, 2012.

 

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In the first quarter of 2012, we sold one of our producing properties in Wyoming, which resulted in gross proceeds of approximately $1,109,000. This property was sold to an unrelated purchaser and pursuant to our amended purchase agreement entered into in July 2011, we were required to pay the related party sellers approximately $283,000 of the proceeds due to their contingent interest and, as a result our net proceeds were $826,000. After deducting the net book value of the property of $309,000, plus the asset retirement obligation assumed by the unrelated purchaser of $16,000, we recognized a gain of approximately $533,000. During the fourth quarter of 2013, we sold one of our producing properties in Wyoming, which resulted in gross proceeds of approximately $1,004,000. This property was sold to an unrelated purchaser and pursuant to our amended purchase agreement entered into in September 2013, we were required to pay the related party sellers approximately $554,000 of the proceeds due to their contingent interest and, as a result our net proceeds were $450,000. After deducting the net book value of the property of $163,000, plus the asset retirement obligation assumed by the unrelated purchaser of $31,000, we recognized a gain of approximately $318,000. We received an overriding royalty interest on each of these properties.

Part of our strategy is to monitor the current production of our properties, seek to develop them with infield drilling, and explore sales and purchases of additional leases and operating wells with upside. We are currently evaluating several opportunities for drilling in Wyoming and Colorado. As part of our evaluation we have entered into participating agreements for three wells in Wyoming. The Company has participated as a working interest owner in three horizontal wells to be drilled in Campbell County, Wyoming in the Turner zone. The following is a description of the wells:

 

  1) The Thielen #1-21 is in Section 21 Township 43N. This well is currently being drilled to a total depth of approximately 15,350 including the lateral. The Company will have an approximate 1.06% working interest.

 

  2) The Thielen #2-21 is in Section 21 Township 43N. This well is scheduled to be drilled in the summer of 2014 and is planned to be drilled to a total depth of approximately 15,330 feet including the lateral. The Company will have an approximate 1.06% working interest.

 

  3) The Starlight Federal 28H is located in Section 7, Township 43N. This well is scheduled to be drilled in the first quarter of 2014 and is planned to be drilled to a total depth of approximately 15,310 including the lateral. The Company will have an approximate 0.7025% working interest.

 

  The Company has not received any results on the wells other then the drilling has been completed and the information is being evaluated.

 

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The following table provides information regarding our oil and natural gas properties and operations by state where the properties are located:

 

     Proved Reserves at 2013 Year-End     Productive Wells
During 2013
     2013 Average
Monthly Production
(BOE)
 
     Quantity
(BOE) (a)
     Pre-Tax
PV 10% (b)
     %
Oil (c)
      

State

           Gross      Net (d)     

Wyoming

     140,646       $ 2,706,850         66.9     28.0         20.5         1,496   

Kansas

     116,712         3,032,319         100.0     8.0         4.3         590   

Colorado

     95,959         1,990,419         38.0     7.0         6.7         744   

Montana

     6,475         18,426         0.0     2.0         1.4         68   
  

 

 

    

 

 

      

 

 

    

 

 

    

 

 

 
     359,792       $ 7,972,742         69.3     45.0         32.9         2,898   
  

 

 

    

 

 

      

 

 

    

 

 

    

 

 

 

 

(a) BOE is defined as one barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil.
(b) The prices used to calculate this measure were $87.49 per barrel of oil and $5.86 per Mcf for natural gas. These prices were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December 31, 2013, which resulted in benchmark prices of $96.78 per barrel for crude oil and $3.67 per MMbtu for natural gas. Benchmark prices were further adjusted on a well by well basis for transportation, quality and basis differentials to arrive at the prices used for this report.
(c) Computed based on BOE using the ratio of six Mcf of natural gas to one barrel of oil.
(d) Net wells are the sum of our fractional working interests owned in gross wells.

Reconciliation of Standardized Measure to PV10

PV10 is the estimated present value of the future net revenues from our proved oil and natural gas reserves before income taxes discounted using a 10% discount rate. PV10 is considered a non-GAAP financial measure because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV10 is widely used by securities analysts and investors when evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that many other companies in the oil and natural gas industry calculate PV10 on the same basis. PV10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. The table below provides a reconciliation of our standardized measure of discounted future net cash flows to our PV10 value:

 

     Standardized
Measure
    PV 10  

Future cash inflows

   $ 25,573,856      $ 25,573,856   

Future production costs

     (10,493,071     (10,493,071

Future development costs

     (880,485     (880,485

Future income taxes

     (2,490,706     —     
  

 

 

   

 

 

 

Future net cash flows

     11,709,593        14,200,300   

10% annual discount

     (5,554,945     (6,452,285
  

 

 

   

 

 

 

Discounted future net cash flows

   $ 6,154,647      $ 7,748,014   
  

 

 

   

 

 

 

The difference between the standardized measure of $6,848,963 and PV10 of $8,442,330 is $1,593,367, which is due to income taxes included in the standardized measure as follows:

 

Undiscounted income taxes

   $ 2,490,706   

Impact of 10% discount factor

     (897,340
  

 

 

 

Discounted impact of income taxes

   $ 1,593,367   
  

 

 

 

 

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Business Strategy

Our business strategy is three-fold in approach.

 

    We plan to and have acquired oil and natural gas operating properties that will provide for the operations of the Company;

 

    We expect to seek to acquire leases that have development possibility either for us to drill or with other companies on a joint venture or farm-out basis. Part of this plan would include the possibility of selling leases and retaining an overriding royalty in the property and a right to buy back into future development; and

 

    We are looking for acquisitions of producing properties with future development.

Competitive Business Conditions

The oil and natural gas industry is intensely competitive, and we compete with numerous other companies engaged in the exploration and production of oil and gas. Many of these companies have substantially greater resources than we have. Not only do they explore for and produce oil and natural gas, but also many carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. The operations of other companies are in many instances able to pay more for exploratory prospects and productive oil and natural gas properties. Many of our competitors also have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or technical resources permit.

Our larger competitors have the resources to be better able to absorb the burden of current and future federal, state, and local laws and regulations more easily than we can, which adversely affects our competitive position. Our ability to locate reserves and acquire interests in properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, we may be at a disadvantage in acquiring producing oil and natural gas properties and bidding for exploratory prospects because we have fewer financial and technical resources than other companies in our industry.

Marketing and Customers

The market for oil and natural gas that we produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets, as adjusted for transportation and quality. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We currently rely on our related party operator to market and sell our production.

Seasonality—Gathering and Processing

Generally, but not always, the demand and price levels for natural gas increase during the colder winter months and decrease during the warmer summer months. More recently, historical natural gas prices have been at ten year lows. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal anomalies such as mild winters and summers sometimes lessen these fluctuations.

Foreign Operations and Export Sales

We do not have any interests, production facilities, or operations in foreign countries.

Governmental Regulations

Our operations are subject to significant, substantive rules, regulations and limitations impacting the oil and natural gas exploration and production industry as a whole, as described below.

Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, and local authorities and agencies. Certain states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the

 

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establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry has increased our cost of doing business and affected our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Transportation of Natural Gas

Historically, the transportation of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the Federal Energy Regulatory Commission (FERC).

In the past, the federal government has 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.

Since 1985, 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. The FERC’s orders are intended to foster increased competition within all phases of the natural gas industry.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects our competitors

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. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.

Environmental Matters

Our operations and properties are, like the oil and natural gas industry in general, subject to extensive and changing federal, state and local laws and regulations relating to both environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and safety and health. The recent trend in environmental regulation is generally toward stricter standards, and this trend is likely to continue. These laws and regulations may require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands.

The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state statutes impose strict and arguably joint and several liabilities on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act (RCRA) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related

 

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products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.

Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (OPA) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide) and particulates with respect to certain of our operations. We are required to maintain such permits or meet general permit requirements. The EPA and designated state agencies have in place regulations concerning discharges of storm water runoff and stationary sources of air emissions. These programs require covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. Most agencies recognize the unique qualities of oil and natural gas exploration and production operations. We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us.

Climate Change

Climate change has become the subject of an important public policy debate. Climate change remains a complex issue, with some scientific research suggesting that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.

Impact of Legislation and Regulation. The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, and regulations that may affect us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows, and could reduce the demand for our products.

Climate change legislation and regulations have been adopted by many states in the US; however, legislation and regulations have not been enacted at the federal level in the US or all states, although Congress and several states are considering adopting climate change legislation. The current state of development of many state and federal climate change regulatory initiatives in areas where we operate makes it difficult to predict with certainty the future impact on us, including accurately estimating the related compliance costs that we may incur.

Indirect Consequences of Regulation or Business Trends. We believe there are risks arising from the global response to climate change.

Physical Impacts of Climate Change on our Costs and Operations. There has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Extreme weather conditions increase our costs, and damage resulting from extreme weather may not be fully insured. However, the extent to which climate change may lead to increased storm or weather hazards affecting our operations is difficult to identify at this time.

Employees

We currently have no full time or part time employees. Our officers serve us in a consulting capacity. We anticipate adding employees and are currently using independent contractors, consultants, attorneys and accountants as necessary, to complement services for operations and regulatory filings. We presently have four independent technical professionals under consulting arrangements, all of whom are available to us on an as needed basis.

Intellectual Property

We do not currently have any patents, trademarks or licenses.

 

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Item 1A. RISK FACTORS

An investment in our common stock involves a high degree of risk. Readers of this report should consider carefully the following risks, along with all of the other information included in this report. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also impair our business operations. If we are unable to prevent events that have a negative effect from occurring, then our business may suffer. Some of the information in this Annual Report on Form 10-K contains forward-looking statements that involve substantial risks and uncertainties. These statements can be identified by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “intend,” “estimate,” and “continue” or other similar words. Statements that contain these words should be carefully read for the following reasons:

 

    The statements may disclose our future expectations;

 

    The statements may contain projections of our future earnings or our future financial condition; and

 

    The statements may state other “forward-looking” information.

Risks Related to Our Business and Industry

We will require significant additional capital in seeking to execute our business plan, which may not be available or may only be available on unfavorable terms.

Our future capital requirements depend on many factors, including development and acquisition opportunities, the availability of debt financing and the cash flow from our operations. To the extent that the funds available are insufficient to meet future capital requirements, we will likely need to reduce our development activity as we did in 2013. Any equity or debt financing, if available at all, may be on terms that are not favorable to us. If we cannot obtain adequate capital on favorable terms or at all, our business, operating results and financial condition will likely be adversely affected.

We do not have any employees and we depend on our chief executive officer and chief financial officer for a significant majority of our management decisions, operations and industry contacts.

Due to our limited operations, we do not have any employees, and our executive officers are retained as independent contractors on a part-time basis. We are heavily dependent upon the efforts of our Chief Executive Officer, Nicholas L. Scheidt, who essentially operates our company and our Chief Financial Officer Donald W. Prosser, who handles the finances and financial filings. We do not have an employment agreement with either officer nor do we have any key man insurance on their life. As we currently do not have a successor to Messrs. Scheidt and Prosser, the loss of either of their services would likely have a material adverse impact on our business.

Our future performance is difficult to evaluate because we have a limited operating history.

Our operations in the natural resources industry commenced with our acquisition of a gas gathering pipeline as of September 2006. In the third quarter of 2011, we purchased various oil and gas producing properties for a base purchase price of $11,000,000. Prior to our third quarter of 2011 asset acquisition, our revenues were minimal and we incurred significant losses. As of December 31, 2013, our accumulated deficit was approximately $16.2 million. With respect to our acquisition of the oil and gas producing properties in 2011, we have little historical financial and operating information available to assist in an evaluation of our Company.

Oil and gas prices must remain at sufficient levels in order for us to operate profitably.

In the event we are able to raise substantial additional capital, we expect to focus on acquiring oil and gas properties that we believe offer profit potential from overlooked and by-passed reserves of oil and natural gas, which will include shut-in wells, in-field development, stripper wells, re-completion and re-working projects. Because production is generally on a decline on these mature properties while operating expenses can be high, declines in oil and gas prices will likely have a greater negative impact on our operations compared to oil and gas companies that focus on newer developed properties.

We may expend substantial funds in acquiring and redeveloping properties which are later determined to not be economically viable.

The search for new oil and gas reserves, development wells or secondary recovery frequently result in unprofitable efforts, not only from dry holes, but also from wells which, though productive, will not produce oil or gas in sufficient quantities to return a profit on the costs incurred. There is no assurance that any production will be obtained from any of the

 

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acreage to be acquired by us, nor are there any assurances that if such production is obtained, it will be profitable. We may expend substantial funds in acquiring and redeveloping properties which are later determined not to be economically viable. All funds so expended may be a total loss to us and which could result in possibly significant impairments in our oil and gas asset base. In such event, our profitability and operations may be materially adversely affected.

The domestic oil and gas exploration and production industry is faced with shortages of personnel and equipment, and such shortages may adversely affect our operations and financial results.

The oil and gas industry, as a whole, suffers from an aging workforce and a shortage of qualified and experienced personnel. Our operations and financial results may be adversely impacted due to difficulties in attracting and retaining such personnel within our Company or within companies that provide materials and services to the industry. The substantial increase in oil prices in 2011 resulted in increased drilling and construction activity in the industry and shortages of personnel and equipment are present in our primary focus areas. Further, our plans will likely require access to services and oil field equipment. Such equipment and operating personnel are currently in short supply.

Restrictions in any future credit agreements may prevent us from engaging in some beneficial transactions.

We are seeking to enter into credit agreements with financial institutions to fund a portion of our anticipated capital requirements. To obtain funds under credit agreements we may be required to accept operating restrictions which would impair or prevent us from future transactions we deem to be beneficial to us.

Competition for experienced technical personnel may negatively impact our operations.

Our acquisition strategy’s success could depend, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. The scope of our operations and our future will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our financial condition and results of operations.

Our success depends on the results of our exploitation, exploration, development and production activities. Oil and natural gas exploration and production activities are subject to numerous significant risks some of which are beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in large part on our proper evaluation and assessment of data obtained through geophysical and geological analyses, production data, and engineering studies. Our evaluations and assessments could ultimately prove to be incorrect. Significant aspects of costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can render a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including:

 

    Shortages of or delays in obtaining equipment and qualified personnel such as we are currently experiencing;

 

    Pressure or irregularities in geological formations;

 

    Equipment failures or accidents;

 

    Adverse weather conditions;

 

    Reductions in oil and natural gas prices;

 

    Issues associated with property titles; and

 

    Delays imposed by or resulting from compliance with regulatory requirements.

Volatile oil and natural gas prices could adversely affect our financial condition and results of operations.

Our most significant market risk is the price of crude oil and natural gas. Management expects energy prices to remain volatile and unpredictable. Moreover, oil and natural gas prices result from numerous factors that are outside of our control, including:

 

    Economic and energy infrastructure disruptions caused by geopolitical factors including but not limited to embargoes and sanctions on major producing countries and actual or threatened acts of war, or terrorist activities particularly with respect to oil producers in the Middle East, Nigeria and Venezuela;

 

    Weather conditions, such as hurricanes, including energy infrastructure disruptions resulting from those conditions;

 

    Changes in the global oil supply, demand and inventories;

 

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    Changes in domestic natural gas supply, demand and inventories;

 

    The price and quantity of foreign imports of oil;

 

    Political conditions in or affecting other oil-producing countries;

 

    General economic conditions in the United Stated and worldwide;

 

    The level of worldwide oil and natural gas exploration and production activity;

 

    Technological advances affecting energy consumption; and

 

    The price and availability of alternative fuels.

Lower oil and natural gas prices not only decrease revenues on a per unit of production basis, but also may reduce the amount of oil and natural gas that we can economically produce negatively impacting estimates of our economically recoverable proved reserves. Substantial or extended declines in oil or natural gas prices may materially and adversely affect our financial condition, results of operations, liquidity and ability to finance operations and planned capital expenditures.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

Oil and natural gas exploration, drilling and production activities are subject to numerous operating risks including the possibility of:

 

    Blowouts, fires and explosions;

 

    Personal injuries and death;

 

    Uninsured or underinsured losses;

 

    Unanticipated, abnormally pressured formations;

 

    Mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses; and

 

    Environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination.

Any of these operating hazards could cause damage to properties, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs, and other environmental damages, which could expose us to significant liabilities.

Seeking to grow our business by purchase of production, expanding existing production, and exploration subjects us to development and other risks.

The search for commercial quantities of oil and natural gas as a business is highly risky. We cannot provide investors with any assurance that any properties in which we obtain a mineral interest will contain commercially exploitable quantities of oil and/or gas. The exploration expenditures to be made by us may not result in the discovery of commercial quantities of oil and/or gas. Problems such as unusual or unexpected formations or pressures, premature declines of reservoirs, invasion of water into producing formations and other conditions involved in oil and gas exploration often result in unsuccessful exploration efforts. If we are unable to find commercially exploitable quantities of oil and gas, and/or we are unable to commercially extract such quantities, we may be forced to abandon or curtail our business plan, and as a result, any investment in us may become worthless.

Future oil and gas price declines or unsuccessful exploration efforts may result in write-downs of our exploration and production asset carrying values.

We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. The capitalized costs of our oil and gas properties, on a field basis, cannot exceed the estimated future net cash flows of that field. If net capitalized costs exceed future net revenues, we must write down the costs of each such field to our estimate of fair market value. Unproved properties are evaluated at the lower of cost or fair market value. Accordingly, a significant decline in oil or gas prices or unsuccessful exploration efforts could cause a future write-down of capitalized costs.

We review the carrying value of our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The impairment analysis is based on then current oil and gas prices in effect. Once incurred, a write-down of oil and gas properties cannot be reversed at a later date even if oil or gas prices increase.

 

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Future oil and gas price declines may affect our ability to raise capital.

If oil and gas prices decrease there will be a corresponding negative impact on the value of our reserves. This could negatively affect our ability to borrow funds or raise equity capital.

Competition in our industry is intense, and many of our competitors have greater financial and technical resources than we do.

We face intense competition from major oil companies, independent oil and gas exploration and production companies, financial buyers and institutional and individual investors who are actively seeking oil and gas properties, along with the equipment, expertise, labor and materials required to operate oil and gas properties. Many of our competitors have financial and technical resources vastly exceeding those available to us, and many oil and gas properties are sold in a competitive bidding process in which our competitors may be able to pay more for development prospects and productive properties or in which our competitors have technological information or expertise to evaluate and successfully bid for the properties that is not available to us. In addition, shortages of equipment, labor or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring and developing profitable properties in the face of this competition.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.

Our internal controls and operations are subject to extensive regulation and reporting obligations and as of December 31, 2013, we concluded that our disclosure controls and procedures were not effective. See Item 9A, “Controls and Procedures”. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, effective internal control over financial reporting may not prevent or detect misstatements. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our shares of common stock.

If we learn of any title defects on the properties we own or acquire, it could have a material adverse effect on our operations and profitability.

We may not be the record owner of interest in our properties and may rely instead on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we have the right to have our interest placed of record. As is customary in the oil and gas industry, a preliminary title examination will be conducted at the time properties or interests are acquired by us. Prior to commencement of operations on such acreage and prior to the acquisition of properties, a title examination will usually be conducted and significant defects remedied before proceeding with operations or the acquisition of proved properties, as appropriate.

Our producing properties are subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. Although we are not aware of any material title defects or disputes with respect to our current and prospective acreage acquisitions, to the extent such defects or disputes exist, we could suffer title failures.

Our officers and directors are engaged in other business activities and conflicts of interest have arisen in their daily activities which may not be resolved in our favor.

Certain conflicts of interest exist between us and our officers and directors. Officers or directors may bring energy prospects to us in which they have an interest. They have other business interests to which they devote their attention, and will be expected to continue to do so. They will also devote management time to our business. As a result, conflicts of interest or potential conflicts of interest may arise from time to time that can be resolved only through the officers and directors exercising such judgment as is consistent with fiduciary duties to their other business interests and to us. See Item 13, “Certain Relationships and Related Transactions, and Director Independence”.

 

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Insurance may not fully recover potential losses.

Although we believe that we are reasonably insured against losses to wells and associated equipment, potential operational related losses could result in a loss of our reserves and properties and materially reduce our ability to self-fund exploration and development activities and property acquisitions. The insurance market, in general, and the energy insurance market in particular, have experienced substantial cost increases over recent years, resulting from significant losses associated with commercial losses. The potential for loss, however, cannot be accurately or reasonably predicted. If we incur substantial damages or liabilities that are not fully covered by insurance or are in excess of policy limits, then our business, results of operations, and financial condition could be materially affected. Also, as is customary in the oil and gas business, we do not carry business interruption insurance. In the future, it is also possible that we will further modify insurance coverage or determine not to purchase some insurance because of high insurance premiums.

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce any earnings we may achieve.

There is intense competition for acquisition opportunities in our industry for attractive oil and gas properties and other exploration and production. 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. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and manage effectively additional employees. 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 earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Negative or downward revisions of oil and gas reserve estimates could adversely affect the trading price of our common stock. Oil and gas reserves and the standardized measure of cash flows represent estimates, which may vary materially over time due to many factors.

The market price of our common stock may be subject to significant decreases due to decreases in our estimated reserves, our estimated cash flows and other factors. Estimated reserves may be subject to downward revision based upon future production, results of future development, prevailing oil and gas prices, prevailing operating and development costs, SEC rules related to proved undeveloped reserves and other factors. There are numerous uncertainties and uncontrollable factors inherent in estimating quantities of oil and gas reserves, projecting future rates of production, and timing of development expenditures.

The estimates of future net cash flows from proved reserves and the standardized measure of proved reserves are based upon various assumptions about prices and costs and future production levels that may prove to be incorrect over time. Any significant variance from the assumptions could result in material differences in the actual quantity of reserves and amount of estimated future net cash flows from estimated oil and gas reserves.

In addition, SEC rules generally require that proved undeveloped reserves that have not been drilled within five years be reclassified out of estimates of proved reserves; although such technically and economically recoverable reserves may be still owned or controlled by us. Accordingly, given the shortages of materials, equipment and human resources prevailing in the industry and also current low natural gas prices we may not drill certain proved undeveloped locations within the established five year time frame and therefore we may be required to reclassify such reserves out of our estimated proved undeveloped reserves. The effect of reclassifying such reserves would result in decreases in estimated proved reserve quantities and therefore could result in decreases in net income and earnings per share, resulting from increased depletion expense and possible impairments. These effects could have an adverse effect on our stock price.

Our properties are subject to influence by other parties that do not allow us to proceed with exploration and expenditures as we may desire.

We do not operate any of our properties. Joint ownership is customary in the oil and gas industry and is generally conducted under the terms of a joint operating agreement (“JOA”), where a single working interest owner is designated as the “operator” of the property. All of our producing oil and gas properties are operated by DNR, an affiliate of one of our officers and directors, Charles Davis. Thus, drilling and operating decisions are not within our sole control. If we disagree with the decision of this operator, we may be required, among other things, to postpone the proposed activity or decline to participate. If we decline to participate, we might be forced to relinquish our interest through “in-or-out” elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate, or forever relinquish its position. Non-consent penalties typically allow participating working interest owners to recover from the proceeds of production, if any, and an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations.

 

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Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated or curtailed as a result of future legislation.

Among the changes contained in the Obama Administration’s Fiscal Year 2013 budget proposal, released by the Office of Management and Budget, is the elimination or deferral of certain U.S. federal income tax deductions and credits currently available to domestic oil and gas exploration companies. Such changes include, but are not limited to, (i) the elimination of current deductions for intangible drilling and development costs; (ii) the elimination of the deduction for certain U.S. production activities for oil and gas properties; (iii) an extension of the amortization period for certain geological and geophysical expenditures and (iv) the repeal of the enhanced oil recovery credit. Some of these same proposals to repeal or limit oil and gas tax deductions and credits have been included in legislation that has recently been considered by Congress. It is unclear whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of the budget proposal, or the passage of bills containing similar changes in U.S. federal income tax law could eliminate or defer certain tax deductions and credits that are currently available with respect to oil and gas exploration and development and could negatively affect our financial results.

The nature of our business and assets may expose us to significant compliance costs and liabilities.

Our operations involving the exploration, production, storage, treatment, and transportation of liquid hydrocarbons, including crude oil, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our operations are also subject to laws and regulations relating to protection of the environment, operational safety, and related employee health and safety matters. Compliance with all of these laws and regulations may represent a significant cost of doing business. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; and the issuance of injunctions that may restrict, inhibit or prohibit our operations; or claims of damages to property or persons.

Compliance with environmental laws and regulations may require us to spend significant resources.

Environmental laws and regulations may: (1) require the acquisition of a permit before well drilling commences; (2) restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; (3) prohibit or limit drilling activities on certain lands lying within wetlands or other protected areas; and (4) impose substantial liabilities for pollution resulting from past or present drilling and production operations. Moreover, changes in Federal and state environmental laws and regulations, as well as how such laws and regulations are administered, could occur and may result in more stringent and costly requirements which could have a significant impact on our operating costs. In general, under various applicable environmental regulations, we may be subject to enforcement action in the form of injunctions, cease and desist orders and administrative, civil and criminal penalties for violations of environmental laws. We may also be subject to liability from third parties for civil claims by affected neighbors arising out of a pollution event. Laws and regulations protecting the environment may, in certain circumstances, impose strict liability rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Such laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time such acts were performed. We believe we are in compliance with applicable environmental and other governmental laws and regulations. In recent years, increased concerns have been raised over the protection of the environment. Legislation to regulate the emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Also, the EPA has recently undertaken significant efforts to collect information regarding greenhouse gas emissions and their effects.

Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for crude oil and natural gas that we produce.

In December 2009, the U.S. Environmental Protection Agency, (“EPA”) determined that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”), present an endangerment to public health and the environment because emissions of such gasses are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one set of rules limit emissions of GHGs from motor vehicles and the other set of rules require certain Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for GHG emissions from certain large stationary sources. The EPA rules have tailored the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities, which may include certain of our operations, on an annual basis.

 

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In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as government reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our production and/or ability to book future reserves.

Hydraulic fracturing involves the injection of water, sand, and chemical additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural gas commissions; however, the EPA, recently asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In February 2012, the U.S. Department of the Interior (the “DOI”) released draft regulations governing hydraulic fracturing on federal and Indian oil and gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing, and monitoring of well-stimulation operations. In addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process are adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and cause us to experience added delays or curtailment in the pursuit of exploration, development, or production activities.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic-fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected to be available by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities and plans to propose these standards by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. These ongoing or proposed studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Colorado, Montana, Pennsylvania, Louisiana, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and additional well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular. These regulations will affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and oil that we can economically produce to the extent that we use hydraulic fracturing. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities on a timely basis following leasing. Delays in obtaining regulatory approvals, drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff.

 

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We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our hedging arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the use of debt or the issuance of equity. Even if our credit reviews are satisfactory, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could adversely affect our financial condition and results of operation.

Risks Related to Our Common Stock

Investors may be diluted in future Common Stock offerings.

The holders of our common stock have no preemptive rights, and the issuance of additional shares of common stock by us may result in a commensurate reduction in an individual shareholder’s percentage ownership in us. The value of an investor’s investment in our convertible preferred stock may decrease to the extent that such dilution reduces the fair value of the shares of common stock.

Our common stock is thinly traded and our share price has fluctuated in the past and may continue to fluctuate in the future.

Our common stock has historically been thinly traded and the market price of our common shares in the over-the-counter market has experienced significant volatility and may continue to fluctuate significantly. The market price of our common shares may be significantly affected by factors such as the announcements of agreements and technological innovations by us or our competitors. In addition, while we cannot assure you that any securities analysts will initiate or maintain research coverage of our company and our shares, any statements or changes in estimates by analysts initiating or covering our shares or relating to the oil and gas industry could result in an immediate and adverse effect on the market price of our shares. Further, we cannot predict the effect, if any, that market sales of shares or the availability of shares for sale will have on the market price of the shares prevailing from time to time. Issuance and sale of a substantial number of shares or the perception that such sales could occur, could have a material adverse effect on the market price of our shares.

Trading in shares of companies, such as ours, have been subject to extreme price and volume fluctuations that have been unrelated or disproportionate to operating or other performance.

Trading on the OTC Market may be volatile and sporadic, which could depress the market price of our common stock and make it difficult for our shareholders to resell their shares.

Our common stock is quoted on the OTC Market. Trading in stock quoted on the OTC Bulletin Board is often thin and characterized by wide fluctuations in trading prices due to many factors that may have little to do with our operations or business prospects. This volatility could depress the market price of our common stock for reasons unrelated to operating performance. Moreover, the OTC Market is not a stock exchange, and trading of securities on the OTC Market is often more sporadic than the trading of securities listed on other stock exchanges such as the NASDAQ Stock Market, New York Stock Exchange or American Stock Exchange. Accordingly, our shareholders may have difficulty reselling any of their shares.

Our common stock is a penny stock. Trading of our stock may be restricted by the SEC’s penny stock regulations and the FINRA’s sales practice requirements, which may limit a shareholders ability to buy and sell our stock.

Our common stock is a penny stock. The SEC has adopted Rule 15g-9 which generally defines penny stock to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and accredited investors. The term accredited investor refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with their spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer must also provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt

 

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from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability or willingness of broker-dealers to trade our securities. We believe that the penny stock rules discourage broker-dealer and investor interest in, and limit the marketability of, our common stock.

FINRA sales practice requirements may also limit a shareholders ability to buy and sell our stock.

In addition to the penny stock rules promulgated by the SEC, which are discussed in the immediately preceding risk factor, FINRA rules require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit the ability to buy and sell our stock and have an adverse effect on the market value for our shares.

There are a substantial number of shares of our common stock eligible for future sale in the public market. The sale of a large number of these shares could cause the market price of our common stock to fall.

There were 12,408,459 shares of our common stock outstanding as of March 31, 2014. As of that date, members of our management and their affiliates beneficially owned approximately 4,766,907 shares of our common stock, representing 38.42% of our outstanding common stock. Sale of a substantial number of these shares would likely have a significant negative effect on the market price of our common stock, particularly if the sales are made over a short period of time.

If our shareholders, particularly management and their affiliates, sell a large number of shares of our common stock, the market price of shares of our common stock could decline significantly. Moreover, the perception in the public market that our management and affiliates might sell shares of our common stock could depress the market price of those shares.

Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.

We have never declared or paid cash dividends on our common stock. We currently intent to retain all future earnings and other cash resources, if any, for the operations and development of our business and do not anticipate paying cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansions. In addition, we may not pay cash dividends on our common stock for so long as any shares of our convertible preferred stock are outstanding. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time and from the issuance of preferred stock should we decide to do so in the future.

Access to Information

Our website address is www.areteindustries.com We make available, free of charge, on the “Filings” section of our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, as soon as reasonably practicable after these reports are electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). We also make available through our website other reports electronically filed with the SEC under the Securities Exchange Act of 1934, including our proxy statements. We do not intend for information contained in our website to be part of this Annual Report on Form 10-K.

Item 1B. UNRESOLVED STAFF COMMENTS

None

 

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Item 2. PROPERTIES

Oil and Natural Gas Properties

The following table lists our oil and natural gas properties by state and field as of December 31, 2013:

 

          Productive
Wells
     Proved
Reserves
 

Field

   County    Gross      Net (a)      (BOE) (b)  

Wyoming:

           

Rex Lake

   Albany      7.0         7.0         12,352   

Buff

   Campbell      4.0         4.0         42,382   

Shippy

   Campbell      1.0         1.0         17,575   

Bobcat Creek

   Converse      1.0         0.6         13,047   

Other

   Various      15.0         7.9         55,291   

Kansas:

           

Big Bow

   Stanton      5.0         1.5         30,058   

Granger Creek

   Clark      1.0         1.0         51,551   

Walz

   Trego      1.0         0.9         26,105   

Other

   Graham      1.0         0.9         8,998   

Colorado:

           

Gemini

   Weld      2.0         2.0         54,623   

Smokey Creek

   Cheyenne      1.0         0.7         31,698   

Wild Horse

   Weld      1.0         1.0         2,415   

Other

   Various      3.0         3.0         7,223   

Montana:

           

Police Coulee

   Toole      2.0         1.4         6,475   
     

 

 

    

 

 

    

 

 

 
        45.0         32.9         359,792   
     

 

 

    

 

 

    

 

 

 

 

(a) Net wells are the sum of our fractional working interests owned in gross wells.
(b) BOE is defined as one barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil.

Gas Gathering System

In September 2006, the Company acquired a gas gathering system (pipeline and compressor station related assets) located in Campbell County, Wyoming. This system was constructed in late 2001 and began operations early in 2002. The system consists of 4.5 miles of 8-inch coated steel pipeline. This pipeline has been shut-in since June 2011 and is not generating revenue. The system has been shut-in due to the low prices of natural gas.

This system has a current throughput capacity of approximately 4 million cubic feet (“MMcf”) of gas per day. Since July 2011, the Company has owned a 100% working interest in all of the coal-bed methane properties that are connected to the Company’s gathering system.

Description of Coal-Bed Methane Properties - Powder River Basin Geology

In December 1994, there were approximately 200 wells in the Powder River Basin producing coal-bed methane gas. Since 1994, over 15,000 gas wells have been drilled in this area and the State of Wyoming and the Bureau of Land Management (“BLM”) have the authority to grant over 15,000 additional drilling permits. Production in 1994 was 2.4 billion cubic feet, and production in 2003 was 3.46 billion cubic feet (Source: Wyoming Oil and Gas Conservation Commission). The average well-life of coal-bed methane well is estimated by the BLM to be eight to ten years.

Gas produced from Powder River Basin coals is almost 100% methane. The gas is generated during the coal forming process and is trapped in the coal beds by water. In order to produce the coal gas, the formation must first be dewatered. As the water is removed from the coal, the gas is desorbed from the coal. All of the coal-bed reservoirs are low pressure and require compression in order for the gas to be delivered to a pipeline transportation system.

 

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Natural gas wells in the Powder River Basin area typically experience sharp declines in production volume in the first several years of production. Production then stabilizes and declines more ratably over a gas well’s average life of approximately eight to ten years. Other factors which influence the initial and long term productivity of the coal-bed methane wells are the depths of the coal fields, the initial gas saturation levels of the coal field and the well spacing.

Office Facilities

We currently lease our office space in Westminster, Colorado for $250 per month from our Chief Financial Officer.

Item 3. LEGAL PROCEEDINGS

None

Item 4. MINE SAFETY DISCLOSURES

Not Applicable.

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock has been quoted on the OTCQB tier of the OTC Markets. Our trading symbol is “ARET.OTCQB”

The following table sets forth the range of high and low trading price information for our common stock for each fiscal quarter for the past two fiscal years as reported by the OTC Markets Inc. and obtained from Yahoo Finance. High and low trading information represents prices between dealers without adjustment for retail mark-ups, markdowns or commissions. On April 10, 2011, we completed a 100 for 1 reverse stock split and the prices below have been adjusted to give effect for the reverse split.

 

     HIGH      LOW  

Year Ended December 31, 2012:

     

First Quarter

   $ 2.00       $ 0.80   

Second Quarter

     1.35         0.54   

Third Quarter

     0.96         0.21   

Fourth Quarter

     0.45         0.21   

Year Ended December 31, 2013:

     

First Quarter

   $ 0.45       $ 0.25   

Second Quarter

     0.35         0.16   

Third Quarter

     0.45         0.16   

Fourth Quarter

     0.40         0.34   

On March 31, 2014, the last reported sales price of our common stock as reported on the OTCQB was approximately $.31 per share.

Holders

As of March 31, 2014, the approximate number of holders of record of shares of our common stock, our only class of trading securities, was approximately 3,900. The number of record holders of our common stock was determined from the records of our transfer agent and does not include numerous beneficial owners of our common stock whose shares are held in street name by various security brokers, dealers, and registered clearing agencies. The number of beneficial shareholders is unknown to us.

 

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Dividends

The Company has not paid any cash dividends with respect to its common stock and it is not anticipated that the Company will pay cash dividends in the foreseeable future. Also, the Company cannot pay cash dividends on its common stock so long as any shares of convertible preferred stock are outstanding. On March 27, 2014, the Company has 10 shares of its Preferred Series A1 outstanding. The Company during the fiscal year December 31, 2013 converted 512.5 shares of its Preferred Series A1 to 5,426,665 shares of its Common Stock.

The Securities Enforcement and Penny Stock Reform Act of 1990

The SEC has adopted rules that regulate broker-dealer practices in connection with transactions in penny stocks. Penny stocks are generally equity securities with a price of less than $5.00 (other than securities registered on certain national securities exchanges or quoted on the Nasdaq system, provided that current price and volume information with respect to transactions in such securities is provided by the exchange or system). Our common shares are currently subject to the penny stock rules.

A purchaser purchasing a penny stock has limitations on the ability to sell the stock. The Company’s no par value common stock constitute a penny stock under the Exchange Act. The classification of a penny stock makes it more difficult for a broker-dealer to sell the stock into a secondary market, which makes it more difficult for a purchaser to liquidate his/her investment. Any broker-dealer engaged by the purchaser for the purpose of selling his or her shares in us will be subject to Rules 15g-1 through 15g-10 of the Exchange Act. Rather than creating a need to comply with those rules, some broker-dealers will refuse to attempt to sell penny stock.

The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from those rules, to deliver a standardized risk disclosure document prepared by the SEC, which:

 

    contains a description of the nature and level of risk in the market for penny stocks in both public offerings and secondary trading;

 

    contains a description of the broker’s or dealer’s duties to the customer and of the rights and remedies available to the customer with respect to a violation to such duties or other requirements of the Exchange Act, as amended;

 

    contains a brief, clear, narrative description of a dealer market, including “bid” and “ask” prices for penny stocks and the significance of the spread between the bid and ask price;

 

    contains a toll-free telephone number for inquiries on disciplinary actions;

 

    defines significant terms in the disclosure document or in the conduct of trading penny stocks; and

 

    contains such other information and is in such form (including language, type, size and format) as the SEC shall require by rule or regulation.

The broker-dealer also must provide, prior to effecting any transaction in a penny stock, to the customer:

 

    the bid and offer quotations for the penny stock;

 

    the compensation of the broker-dealer and its salesperson in the transaction;

 

    the number of shares to which such bid and ask prices apply, or other comparable information relating to the depth and liquidity of the market for such stock; and

 

    monthly account statements showing the market value of each penny stock held in the customer’s account.

In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from those rules; the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written acknowledgment of the receipt of a risk disclosure statement, a written agreement to transactions involving penny stocks, and a signed and dated copy of a written suitability statement. These disclosure requirements have the effect of reducing the trading activity in the secondary market for our stock. Thus, shareholders may have difficulty selling their securities.

Our Transfer Agent

ComputerShare Investor Services is the transfer agent for our Common Stock. ComputerShare can be contacted at 250 Royal Street, Canton, MA 02021.

 

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Securities Authorized for Issuance Under Equity Compensation Plans

We do not have any equity compensation plans in effect.

Recent Sales of Unregistered Securities

In the fourth quarter of 2013 the Company issued restricted shares of it’s common stock to five of its officers and directors in exchange for accrued directors fees valued at a total of $35,415 or 72,170 shares for the period July 1, 2012 to November 30, 2013. The Company issued 44,823 shares of common stock for payment of $30,000 fees accrued to officers and a related party consultant. The Company issued of common stock for payment of accrued consulting fee to a former director of 20,000 shares valued at $6,000. The Company issued of common stock for payment of a loan fee to a unrelated party of 20,000 shares valued at $6,000. All of these common stock shares were sold in reliance upon exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended (“Securities Act”). These securities qualified for exemption under Section 4(2) of the Securities Act because the issuance by the Company did not involve a “public offering”. Each issuance was not a public offering based upon the following factors: (i) a limited number of securities were issued to a limited number of offerees; (ii) there was no public solicitation; (iii) each offers was an “accredited investor” as such term is defined by Rule 501 under Securities Act; and (iv) the investment intent of the offerees.

Repurchases of Equity Securities of the Issuer

None

Item 6. SELECTED FINANCIAL DATA

As a smaller reporting issuer (as defined by in Item 10(f)(1) of Regulation S-K), the Company is not required to report selected financial data specified in Item 301 of Regulation S-K.

 

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General Overview

We discuss and provide below our analysis of the following:

 

    Critical accounting policies;

 

    Results of operations;

 

    Liquidity and capital resources;

 

    Contractual obligations and commercial commitments;

 

    Off-balance sheet arrangements;

 

    New accounting pronouncements; and

 

    Controls and procedures.

As of December 31, 2013, the Company had a working capital deficit of $619,427 and a balance of cash and equivalents of $476,000. For the past few years we have obtained loans and incurred significant operating payables, primarily from related parties, substantially all of which have been restructured and are current as of March 31, 2014.

In the third quarter of 2011, we completed an acquisition of oil and natural gas properties in Montana, Wyoming, Colorado and Kansas. These properties include several proved undeveloped and probable drilling opportunities. However, due to our working capital deficit discussed above, our primary challenge over the next several months is to obtain additional financing to primarily address the significant working capital deficit and secondarily to seek to exploit existing drilling opportunities and possibly to acquire additional properties. We have sold some of our properties while retaining overriding royalty interests for future upside upon further development of the properties. In addition, from time to time we review opportunities for the purchase of production and underdeveloped oil and gas leases for future development. In order to purchase properties or begin substantive drilling activities we must obtain additional financing, which cannot be assured. We rely heavily on the skills of our board members in the areas of business development, capital acquisition, corporate visibility, oil and gas development, geology and operations.

There are no assurances that we can resolve our pressing capital needs, and although we have revenue from operations, our ability to execute our plans will still be dependent on our ability to raise additional capital. We have not received a commitment to finance the drilling development plan we would like to implement. Our cash flow is dependent on the prices for crude oil. We have entered into a participation agreement with an unrelated third party to participate in three wells that we had interest in the leases. On January 28, 2014, we entered into a line of credit for $1,500,000 of which we have drawn $485,000. We plan to use part of the balance for further development of these wells and other opportunities in the same fields.

While we seek to reduce the amount of our variable costs on an ongoing basis, it is difficult to reduce or offset our fixed expenses related to office expense, legal, accounting, transfer agent fees, reporting, corporate governance, and shareholder communications. We also incur cash costs for the due diligence, reserve studies, audits, and legal cost for these proposed acquisitions of oil and gas properties.

Our future expectation is that monthly operating expenses will remain as low as possible until we can raise additional capital address our working capital deficit.

Critical Accounting Policies

The Company has identified the accounting policies described below as critical to its business operations and the understanding of the Company’s results of operations. The impact and any associated risks related to these policies on the Company’s business operations is discussed throughout this section where such policies affect the Company’s reported and expected financial results. The preparation of our consolidated financial statements requires the Company to make estimates and assumptions that affect the reported amount of assets and liabilities of the Company, revenues and expenses of the Company during the reporting period, and contingent assets and liabilities as of the date of the Company’s consolidated financial statements. There can be no assurance that the actual results will not differ from those estimates.

Revenue Recognition

We record revenue from the sale of natural gas, NGL’s and crude oil when delivery to the purchaser has occurred and title has transferred. We use the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by us. In addition, we record revenue for its share of gas sold by other owners that cannot be

 

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volumetrically balanced in the future due to insufficient remaining reserves. We also reduce revenue for other owners’ gas sold by us that cannot be volumetrically balanced in the future due to insufficient remaining reserves. Our remaining over- and under-produced gas balancing positions are considered in our proved oil and gas reserves. Gas imbalances at December 31, 2012 and 2013 were not material.

Use of Estimates

Preparation of our financial statements in accordance with GAAP requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The most significant areas requiring the use of assumptions, judgments and estimates relate to the volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization, which we refer to as DD&A, the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, impairments of undeveloped properties, and in valuing stock-based payment awards.

Oil and Gas Producing Activities

In January 2010, the Financial Accounting Standards Board, which we refer to as the FASB, issued authoritative oil and gas reserve estimation and disclosure guidance that was effective for the Company beginning in 2010. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC final rule, “Modernization of Oil and Gas Reporting”, which was also effective in 2010.

Our oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production DD&A rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unevaluated oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage.

We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents, BOE, at the rate of six Mcf to one barrel of oil. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.

Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such

 

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costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Consolidated Statements of Operations.

Stock-based Compensation

We have not granted any stock options or warrants during the years ended December 31, 2012 and 2013 and no options or warrants were outstanding at any time during these years. We have issued shares of common stock for services performed by officers, directors and unrelated parties during 2012 and 2013. We have recorded these transactions based on the value of the services or the value of the common stock, whichever is more readily determinable.

Results of Operations for the Years Ended December 31, 2012 and 2013

Presented below is a discussion of our results of operations for the years ended December 31, 2012 and 2013.

Oil and Gas Producing Activities

On July 29, 2011, we entered into a purchase and sale agreement which resulted in our acquisition of producing oil and gas properties in Wyoming, Colorado, Kansas and Montana. Accordingly, we did not have any oil and gas producing activities prior to July 29, 2011. Presented below is a summary of our oil and gas operations for the years ended December 31, 2012 and 2013:

 

     2012     2013  

Oil sales

   $ 1,883,856      $ 1,791,451   

Natural gas sales

     371,270        434,230   

Royalty revenues

     —          533   

Sale of oil and natural gas properties

     533,048        347,888   
  

 

 

   

 

 

 

Total revenue

     2,788,174        2,574,102   

Production taxes

     (187,756     (187,594

Lease operating expense

     (824,027     (679,172

Depreciation, depletion, amortization and accretion (“DD&A”)

     (968,696     (665,123
  

 

 

   

 

 

 

Net

   $ 807,695      $ 1,042,213   
  

 

 

   

 

 

 

Net barrels of oil sold

     25,356        21,304   

Net Mcf of gas sold

     89,203        82,207   

Net Barrels of Oil Equivalent (“BOE”) sold

     40,223        35,005   

Average price per barrel of oil sold

   $ 74.30      $ 84.09   
  

 

 

   

 

 

 

Average price for per Mcf of natural gas sold

   $ 4.16      $ 5.28   
  

 

 

   

 

 

 

Lease operating expense per BOE

   $ 20.49      $ 19.40   
  

 

 

   

 

 

 

DD&A per BOE

   $ 24.08      $ 19.01   
  

 

 

   

 

 

 

The average oil price for 2013 was $84.09 per barrel, a increase of 13.18% compared to $74.30 per barrel for 2012. Our average natural gas price, including proceeds from sales of natural gas liquids, amounted to $5.28 per Mcf for 2013, which is a increase of 26.92% compared to $4.16 per Mcf for 2012.

Production taxes were approximately 8.4% of our oil and gas sales for 2013 compared to 8.3% for 2012. Lease operating expense averaged $19.40 per BOE for 2013, a decrease of 5.6% compared to $20.49 per BOE for 2012.

For 2013 our DD&A per BOE was $19.00 compared to $24.08 per BOE for 2012. DD&A expense for 2013 was $665,123 compared to $968,696 for 2012. The decrease was primarily due to changes in estimated remaining lives of wells and reserves in 2013. Other factors that resulted in higher DD&A for the 2012 period included an 8.7% downward revision in reserve quantities primarily due to lower oil and gas prices in 2012; adjustments to the well by well purchase price

 

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allocation during the fourth quarter of 2011; capitalized costs were higher due to capitalized workovers and major repairs to several of our wells; and we revised our estimates for plugging and abandonment costs which increased net capitalized costs subject to DD&A.

During the fourth quarter of 2013, we sold one of our producing properties, which resulted in gross proceeds of approximately $1,004,000. This property was sold to an unrelated purchaser and pursuant to our amended purchase agreement entered into in September 2013, we were required to pay the related party sellers approximately $554,000 of the proceeds due to their contingent interest and, as a result our net proceeds were $450,000. After deducting the net book value of the property of $163,000, plus the asset retirement obligation assumed by the unrelated purchaser of $31,000, we recognized a gain of approximately $318,000.

During the first quarter of 2012, we sold one of our producing properties, which resulted in gross proceeds of approximately $1,109,000. This property was sold to an unrelated purchaser and pursuant to our amended purchase agreement entered into in July 2011, we were required to pay the related party sellers approximately $283,000 of the proceeds due to their contingent interest and, as a result our net proceeds were $826,000. After deducting the net book value of the property of $309,000, plus the asset retirement obligation assumed by the unrelated purchaser of $16,000, we recognized a gain of approximately $533,000.

We expect to periodically evaluate our portfolio of properties and sell additional properties if we believe a sale can be completed on terms that provide attractive returns.

Gas Gathering Activities

We have owned and operated a natural gas gathering system (pipeline and compressor station) for coal bed methane properties in the Powder River Basin of Wyoming since 2006. Due to a reduction in natural gas prices, all wells in the field have been shut-in since June 2011. The system has been shut-in due to low natural gas prices.

Presented below is a summary of operating costs for the years ended December 31, 2012 and 2013:

 

     2012      2013      Percent
Change
 

Related party- cost of production

   $ —         $ —           —     
  

 

 

    

 

 

    

 

 

 

Unrelated parties:

        

Compressor rental

     —           —           —     

Pumper costs

     —           —           —     

Transportation

     —           —           —     

Property taxes

     5,101         4,470         (12.4 %) 

Land rent, utilities, repairs and other

     10,570         9,670         (8.5 %) 
  

 

 

    

 

 

    

 

 

 

Total unrelated party costs

     15,671         14,140         (9.8 %) 
  

 

 

    

 

 

    

 

 

 

Total

   $ 15,671       $ 14,140         (9.8 %) 
  

 

 

    

 

 

    

 

 

 

Depreciation expense related to the gas gathering system was $44,219 for both 2012 and 2013.

In July 2011, we acquired the entire field of coal bed methane wells as part of our property acquisition discussed above. While these wells are not economic at current prices being received for natural gas related to the production capability from the existing geologic formation, we have geologic and engineering data that suggest gas reserves exist on these properties by drilling new wells and/or recompleting the existing wells to several new geologic formations. While we believe that reserves exist, we do not expect to undertake any drilling activities on this property until natural gas prices increase significantly. We currently believe we should be able to recover our net capitalized costs related to these properties and the related gas gathering system. However, we are continuing to evaluate our alternatives and there is a possibility that an impairment charge will be required in the future.

 

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General and Administrative

Presented below is a summary of general and administrative expenses for the years ended December 31, 2012 and 2013:

 

     2012      2013      Change  

Director fees

   $ 63,615       $ 2,250       $ (61,365

Investor relations

     279,775         98,505         (181,270

Legal, auditing and professional services

     191,876         147,348         (44,528

Consulting and executive services:

        

Related parties

     409,000         123,000         (286,000

Unrelated parties

     133,186         —           (133,186

Other administrative expenses

     83,874         59,712         (24,162

Depreciation

     570         570         —     
  

 

 

    

 

 

    

 

 

 

Total general and administrative expenses

   $ 1,161,896       $ 431,385       $ (730,511
  

 

 

    

 

 

    

 

 

 

General and administrative expenses decreased by $730,511 for 2013 compared to 2012, primarily due to decreases in investor relations of $181,270; director fees of $61,365; legal, auditing and professional fees of $44,528; and consulting and executive services (related and unrelated parties) of $419,186.

The decrease in investor relations costs of $181,270 was due to substantial activities related to investment banking, market information and shareholder communication services that were performed in 2012 and we completed the amortization of the cost of a three year contract in February 2013 or a savings of $149,165. Effective July 1, 2012, director fees payable to each of the Company’s five directors was reduced from a monthly fee of $3,000 to a fee equal to 300 shares of the Company’s common stock for each meeting attended. The fair value of shares issuable under this arrangement was $2,250 resulting in a cost reduction of $61,365 for 2013. The fair value of shares issuable under this arrangement was $3,615 resulting in a cost reduction of $56,385 for 2012 verses 2011. The decrease in consulting fees paid to unrelated parties of $133,186 was primarily attributable the expiration of a consulting contract in June of 2012 that was not renewed and no acquisition review of potential properties. The costs for legal, auditing, and professional fees were reduced by $44,528 in 2013 primarily due to not using an accounting professional in 2013.

Consulting and executive services incurred with related parties decreased by $286,000 for 2013. The board of directors in 2012 revisited the arrangement with DNR Oil & Gas, Inc. and its principals. The following is an explanation of the arrangement with DNR Oil & Gas, Inc.:

 

    Effective October 1, 2011, the Company entered into an Operator Agreement with DNR to provide executive level operations expertise for our existing and prospective oil and properties. The Operator Agreement provided for a monthly charge of $23,000 through July 2012 and a reduction to $18,000 beginning in August 2012. The total charge under the Operator Agreement was $246,000 for 2012, of which $96,000 was allocated to lease operating expense and $150,000 was allocated to general and administrative expenses. The 2013 fees under this arrangement were a total of $216,000 of which $96,000 was allocated to lease operating expense and $120,000 was allocated to general and administrative expenses. DNR is an affiliate of Charles B. Davis, an executive officer and director of the Company.

 

    For the period from January 2012 through July 2012, the agreement called for the payment of the fees for executive, administrative and operational services in the aggregate amount of $15,000 per month to three individuals who are directors and/or stockholders of the Company. These fees are payable in shares of the Company’s common stock based on the closing price on the last day of the month for which the services are performed. For 2012, the Company incurred aggregate fees of $60,000 under this arrangement and no fees for 2013.

 

    During 2012, the Company amended a consulting agreement with an affiliate of a shareholder and director that provided for a wide range of financial, regulatory and corporate structure services. As a result of this amendment the Company paid $50,000 in cash and issued 85,000 shares of common stock with a fair market value of $50,000 and we had no payments in 2013.

 

    For the period from January 2012 through July 2012, the Company incurred executive and accounting fees of $40,000 from an officer and director and no expenses incurred in 2013. During 2012 and 2013, the Company incurred $250 per month for rent payable to an officer and director for the Company’s office.

 

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Operating income (loss)

Income from operations for the year ended December 31, 2013 was $552,469 compared to (loss) from operations of $(414,091) for the year ended December 31, 2012. The increase in of $966,560 was primarily due to the reduction in items discussed above relating to the oil and natural gas operations, gas gathering activities, and general and lower administrative expenses, less the net of gains on sale of oil and gas properties of $185,160 between the amounts for the years ended December 31, 2013 and 2012.

Interest Expense

Interest expense increased from $80,190 for 2012 to $132,168 for 2013, the increase of $51,978. The increase was due primarily to the line credit we incurred to pay the preferred cost dividend and some operating costs in the second quarter 2013.

Net income applicable to common shareholders

For the year ended December 31, 2013, net income applicable to common shareholders used in computing basic net income per share applicable to common shareholders included a $3,160,026 discount on the redemption of 512.5 shares of the Company’s Series A1 Preferred Stock. The discount on the preferred stock redemption is the difference between the carrying value per share of the redeemed preferred shares and the $0.75 per share paid by the Company to the preferred shareholders.

Liquidity and Capital Resources

We had a working capital deficit as of December 31, 2013 of approximately $619,427, compared to a working capital deficit of $1,939,000 at December 31, 2012. We generated positive operating cash flow of approximately $384,000 for 2013 compared to operating cash flow of approximately $355,000 for 2012.

During 2013 our investing activities provided net cash of $172,000. We had capital expenditures of $307,000. During 2013, we generated net proceeds of approximately $479,000 from the sale of a 100% working interest in an oil and gas property and the sale of some equipment. We realized a gain of approximately $348,000 on the sale of this property and equipment. The 2012 investing activities used net cash of $109,000 that included capital expenditures of $935,000, of which approximately $618,000 was acquisition costs paid to related parties for the properties acquired in the third quarter 2011. For 2012, we generated net proceeds of approximately $826,000 from the sale of a 100% working interest in an oil and gas property. We realized a gain of approximately $533,000 on the sale of this property.

During 2013 our financing activities used net cash of approximately $86,000. The 2013 financing activities included borrowings of approximately $1,043,000. These funds were needed to fund our operations as well as to make a $392,000 Preferred Stock Series A dividend payment, redemption of Preferred Stock Series A of $50,000, and repayment of notes payable of $687,000. During 2012, our financing activities used net cash of approximately $458,000. During 2012 we borrowed $825,000 and repaid borrowings of approximately $432,000. During 2012 we also paid approximately $784,000 for dividends on our preferred stock and $67,000 of offering costs that were incurred in connection with our 2011 private placement of preferred stock.

On September 29, 2012, we borrowed $425,000 under a note agreement that provides for interest at a stated annual rate of 12% (effective rate of 17.8%) with unpaid principal and interest due on March 29, 2013. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other asset sales to the note holder to secure the debt. The note holder is 100% owned by a director and shareholder of the Company. The net proceeds from this loan were primarily used to pay approximately $392,000 of preferred stock dividends that were declared in September 2012 and paid on October 1, 2012.

On April 29, 2013, the Company executed a promissory note under which the Company agreed to pay Apex Financial Services Corp, a Colorado corporation, (“Apex”) the principal sum of $1,000,000, with interest accruing at an annual rate of 7.5%, with principal and interest due on May 31, 2014. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other assets sales to Apex to secure the debt. Apex is 100% owned by our CEO, director, and shareholder, Nicholas L. Scheidt. The Company borrowed the full amount of principal on the note, and also paid a loan fee of $10,000. In the event of default on the note and failure to cure the default in ten days, Apex may accelerate payment and the annual default interest rate on the note will accrue at 18%. Default includes failure to pay the note when due or if the Company borrows any other monies or offers security in the Company or in the collateral securing the note prior to the note being paid in full. The proceeds from the loan were used to pay the Series A1 preferred stock dividend and other working capital needs.

We also expect to evaluate acquisitions that are consistent with our business objective of acquiring interests in traditional oil and gas ventures, and seeking properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas. The Company has participated as a working interest owner in three horizontal wells to be drilled in Campbell County, Wyoming in the Turner zone. The following is a description of the wells:

 

  1) The Thielen #1-21 is in Section 21 Township 43N. This well is currently being drilled to a total depth of approximately 15,350 including the lateral. The Company will have an approximate 1.06% working interest.

 

  2) The Thielen #2-21 is in Section 21 Township 43N. This well is scheduled to be drilled in the summer of 2014 and is planned to be drilled to a total depth of approximately 15,330 feet including the lateral. The Company will have an approximate 1.06% working interest.

 

  3) The Starlight Federal 28H is located in Section 7, Township 43N. This well is scheduled to be drilled in the first quarter of 2014 and is planned to be drilled to a total depth of approximately 15,310 including the lateral. The Company will have an approximate 0.7025% working interest.

The Company has not received any results on the wells other then the drilling has been completed and the information is being evaluated.

 

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In order to execute our development drilling plans and to acquire additional interests in oil and gas properties that meet our objectives, we need to obtain significant additional financing. From the time we acquired our existing properties in July 2011, we have sold our interests in some of those properties, which resulted in aggregate net proceeds from three sales of $6,377,000, which was used to repay acquisition indebtedness. We intend to only sell properties that can be liquidated for a premium and there can be no assurance that we will continue to generate any proceeds from the sale of our properties.

The following recent financings are part of the funding of our business plan:

1). Bank Line of Credit

On January 28, 2014, we entered into a line of credit loan agreement with Citywide Bank for $1,500,000 due January 28, 2015. The terms of the note are as follows: 1) the accrued interest is payable monthly starting February 28, 2014, 2) the interest rate is variable based on an index calculated based on a prime rate as published by the Wall Street Journal index (currently 3.25%) plus an add on index with the current and minimum rate of 6.5%., 3) the note has draw provisions, with the first draw of $479,701, 4) the note is secured by seven wells and leases owned by the Company, a certificate of deposit for $500,000 at CityWide Bank pledged by a unrated third party, and 5) the personal guarantee of the Nicholas Scheidt, Chief Executive Officer. The amount eligible for borrowing on the Credit Facility is limited to the lesser of (i) 65% of the Company’s PV10 value of its carbon reserves based upon the most current engineering reserve report or (ii) 48 month cumulative cash flow based upon the most current engineering reserve report. In addition to the borrowing base limitation, the Company is required to maintain and meet certain affirmative and negative covenants and conditions in order to draw advances on the Credit Facility. The Credit Facility contains certain representations, warranties, and affirmative and negative covenants applicable to the Company, which are customarily applicable to senior secured loan facilities. Key covenants include limitations on indebtedness, restricted payments, creation of liens on oil and gas properties, hedging transactions, mergers and consolidations, sales of assets, use of loan proceeds, change in business, and change in control. The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 21% per annum. In addition, the Credit Facility contains customary events of default, including: (a) failure to pay any obligations when due; (b) failure to comply with certain restrictive covenants; (c) false or misleading representations or warranties; (d) defaults of other indebtedness; (e) specified events of bankruptcy, insolvency or similar proceedings; (f) one or more final, non-appealable judgments in excess of $50,000 that is not covered by insurance; (g) change in control (25% threshold); (h) negative events affecting the Guarantor; and (i) lender in good faith believes itself insecure. In an event of default arising from the specified events, the Credit Facility provides that the commitments thereunder will terminate and the Lender may take such other actions as permitted including, declaring any principal and accrued interest owed on the line of credit to become immediately due and payable. The Credit Facility is secured by a security interest in substantially all of the assets of the Company, pursuant to a Security Agreement, Deed of Trust and Assignment of As-Extracted Collateral entered into between the Company and Citywide Banks.

2) Related Party Notes Payable

On January 1, 2014, we memorialized certain of our short-term liabilities into formal promissory notes. These outstanding advances and other notes payable are now included in single promissory notes, all have been reported previously in our financial statements. Information concerning these promissory notes is set forth in the table below.

 

Name of Holder

  

Position

   Principal
Amount
     Interest
Rate
    Monthly
P&I
Payment
Amount
     Number
of
Monthly
Payments

Donald W. Prosser

   CFO & Director    $ 28,500         7.00   $ 564.33       60

Charles B. Davis

   COO & Director    $ 66,500         7.00   $ 1,316.78       60

William Stewart

   Director    $ 49,500         7.00   $ 980.16       36

The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 18% per annum.

 

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In addition, we also issued an unsecured promissory note in the amount of $792,151 on January 1, 2014 to DNR Oil & Gas, Inc. (“DNR”). DNR is a company controlled by one of our directors, Charles B. Davis. The DNR note accrues interest at the rate of 2.50% for the calendar years 2014 and 2015, 4.00% for the calendar year 2016, 6.00% for the calendar year 2017 and 8.00% for the remainder of the term of the DNR note. The DNR note matures on January 1, 2019. The DNR note requires payments as follows:

 

    One payment of $250,000 in 2016;

 

    One payment of $250,000 in 2017;

 

    One payment of $250,000 in 2018; and

 

    The balance of principal and accrued interest on or before January 1, 2019.

The DNR note contains customary default and acceleration provisions and provides for a default interest rate of 18% per annum.

The DNR note is subordinate to the bank line of credit.

3)Extension of Existing Promissory Notes

In June 2013, in connection with the conversions of Series A1 Preferred Stock by Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP, the Company issued unsecured promissory notes in the original principal amounts of $48,000 and $552,000, respectively, with interest at 7% per annum payable quarterly and all unpaid interest and principal due on July 23, 2014. In connection with our new line of credit, we have agreed with the holders of these two existing notes to make a partial prepayment on the principal balance of the Notes in exchange for an extension of the maturity date to January 27, 2015. Information concerning the principal pay down and new maturity date is set forth in the following table.

 

Name of Holder

   Principal Balance
Before Pay down
     Principal
Pay down
     Remaining
Principal Balance
 

Burlingame Equity Investors II, LP

   $ 44,000       $ 17,511       $ 26,489   

Burlingame Equity Investors Master Fund, LP

   $ 506,000       $ 232,489       $ 273,511   

If oil and gas prices decrease materially from current levels and additional debt or equity funding is unavailable on acceptable terms, or at all, our strategy would include some or all of the following: (i) defer development drilling on our existing properties, (ii) forego additional oil and gas property acquisitions, (iii) shut-in any marginal or uneconomic wells, (iv) attempt to negotiate the issuance of common stock in exchange for services, (v) pay preferred stock dividends through the issuance of our common stock, and (vi) review and implement other opportunities to reduce general, administrative and operating expenses.

Contractual Obligations and Commercial Commitments

As of December 31, 2013, we have future minimum lease payments of approximately $6,000. This amount is payable during the years ending December 31, 2014, 2015, 2016, 2017 and after 2018 in the amounts of $1,000, $1,000, $1,000, $1,000, and $2,000, respectively.

Off-Balance Sheet Arrangements

In connection with the related party acquisition of oil and gas properties in the third quarter of 2011, we acquired interests in certain geologic zones of the properties. For a period of ten years after the closing date, the Colorado and Kansas properties provide for additional consideration that is payable to Sellers based on increases in Nymex prices for oil and natural gas, without regard to changes in the Company’s oil and natural gas reserves (referred to as the “Price Increase Factor”). If Nymex thresholds of $90, $100, $110, $125 and $150 per barrel of oil are exceeded for periods of 61 days or more, incremental purchase consideration of $250,000, $250,000, $500,000, $500,000 and $2,000,000, respectively, will be payable to Sellers. Similarly, if Nymex thresholds of $5.00, $6.00, $7.50, $10.00 and $12.00 per MMbtu of natural gas are exceeded for periods of 61 days or more, incremental purchase consideration of $50,000, $50,000, $150,000, $250,000 and $250,000, respectively, will be payable to Sellers.

 

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The Colorado and Kansas properties also provide for additional consideration that is payable to Sellers if reserves classified as “possible” are converted to “proved producing reserves” through drilling or recompletion activities over a period of ten years after the closing date (referred to as the “Possible Reserve Factor”). For such increases in oil reserves, the Sellers are entitled to additional consideration of $250,000 for each increase of 20,000 net barrels; and for such increases in natural gas reserves, the Sellers are entitled to additional consideration of $150,000 for each increase of 150,000 Mcf of natural gas.

The Possible Reserve Factor also requires a multiplier effect from 1 to 5 depending on the Price Increase Factor that is effective when the proved producing reserves are obtained. For example, the Possible Reserve Factor consideration would be multiplied by 2 if the oil Price Increase Factor of $100 is in effect when the proved producing reserves are confirmed. Similarly, the Possible Reserve Factor consideration would be multiplied by 2 if a natural gas Price Increase Factor of $6.00 per MMbtu is in effect when the proved producing natural gas reserves are confirmed. The maximum increase in purchase price for the Kansas and Colorado properties is limited to $5 million.

Additional consideration is also payable for the properties located in Wyoming to the extent that the Company increases proved producing reserves through future drilling or recompletion activities in formations that are not producing as of the closing date under the Possible Reserve Factor. Similar to the properties in Colorado and Kansas, the Possible Reserve Factor will be multiplied by a factor of 1 to 5 depending on the Price Increase Factor that is effective when the proved producing reserves are obtained.

Furthermore, if the Company sells any of the properties in Wyoming, the Sellers have retained an interest of 70% in the net sales proceeds (after the Company receives a recovery of 125% of the original agreed-upon allocation as contained in the table above).

The maximum increase in purchase price (including Sellers retained interest of 70% for the Wyoming properties discussed in the preceding paragraph) for all properties in all states is limited to $25 million. Due to the sale of the Separate Interests discussed below, accrual of $500,000 due to sustained increases in oil prices over $100 per barrel, and the sale of a second property in February 2012, and third property in December 2013, the maximum future consideration has been reduced by approximately $5.8 million to $19.2 million as of December 31, 2013.

SEC Investigation

The Denver Regional Office of the Securities and Exchange Commission is conducting a non-public, formal, investigation (“SEC Investigation”) to determine whether there have been violations of certain provisions of the federal securities laws relating to the Company, its management and third parties. The principal areas of the SEC Investigation relate to the sale of certain Company securities, possible trading manipulation activities with respect to the Company’s common stock, and potential violations of the federal broker-dealer registration laws by persons or entities in connection with the purchase or sale of the Company’s securities. To date, neither the Company nor any of its directors, officers, or employees have been accused of any wrongdoing by the SEC. We also have been informed by the SEC that the existence of this investigation does not mean that the SEC has concluded that anyone has broken the law or that the SEC has a negative opinion of any person, entity, or security. We have been cooperating fully with the SEC. We cannot reasonably estimate the timing of the SEC investigation, nor can we predict whether or not it might have a material adverse effect on our business.

New Accounting Pronouncements

In January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-1, Balance Sheet: Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which amended FASB Accounting Standards Codification (“ASC”) Topic 210, Balance Sheet. The main objective in developing this update was to address implementation issues about the scope of ASU 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities. The amendments clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This provision is effective for fiscal years beginning on or after January 1, 2013. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.

 

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In February 2013, the FASB issued ASU 2013-2, Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which amended ASC Topic 220, Comprehensive Income. The objective of this update was to improve the reporting of reclassifications out of accumulated other comprehensive income. The amendment did not change the requirements for reporting net income or other comprehensive income in financial statements. However, the amendment required an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This provision is effective for interim and annual periods beginning after December 15, 2012. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.

In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the Company’s financial statements upon adoption.

 

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

Report of Independent Registered Public Accounting Firm

     34   

Consolidated Balance Sheets – December 31, 2012 and 2013

     35   

Consolidated Statements of Operations – For the years ended December 31, 2012 and 2013

     37   

Consolidated Statements of Stockholders’ Equity – For the years ended December 31, 2012 and 2013

     38   

Consolidated Statements of Cash Flows – For the years ended December 31, 2012 and 2013

     39   

Notes to Consolidated Financial Statements

     40   

 

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CAUSEY DEMGEN & MOORE P.C.

1125 Seventeenth Street, Suite 1450

Denver, Colorado 80202

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Arête Industries, Inc.

We have audited the accompanying consolidated balance sheet of Arête Industries, Inc. and Subsidiaries as of December 31, 2012 and 2013, and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Arête Industries, Inc. and Subsidiaries at December 31, 2012 and 2013, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

 

Denver, Colorado

April 14, 2014

  

/s/ CAUSEY DEMGEN & MOORE P.C.

 

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ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31,

 

     2012     2013  
ASSETS     

Current Assets:

    

Cash and equivalents

   $ 6,921      $ 476,323   

Receivable from DNR Oil & Gas, Inc.:

    

Oil and gas sales, net of production costs

     87,989        230,029   

Other

     61,243        2,368   

Prepaid expenses and other

     61,034        38,177   
  

 

 

   

 

 

 

Total Current Assets

     217,187        746,897   
  

 

 

   

 

 

 

Property and Equipment:

    

Oil and gas properties, at cost, successful efforts method:

    

Proved properties

     9,389,245        9,555,897   

Unevaluated properties

     314,336        314,336   

Natural gas gathering system

     442,195        442,195   

Furniture and equipment

     22,522        22,522   
  

 

 

   

 

 

 

Total property and equipment

     10,168,298        10,334,950   

Less accumulated depreciation, depletion and amortization

     (1,499,284     (2,094,337
  

 

 

   

 

 

 

Net Property and Equipment

     8,669,014        8,240,613   
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 8,886,201      $ 8,987,510   
  

 

 

   

 

 

 

 

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LIABILITIES AND STOCKHOLDERS’ EQUITY

  

Current Liabilities:

    

Accounts payable:

    

Payable to DNR Oil & Gas, Inc.:

    

Oil and gas property acquisition costs

   $ 250,000      $ —     

Gas gathering operating costs

     436,403        —     

Operator fees and other

     159,748        36,000   

Unrelated parties

     92,943        17,806   

Notes and advances payable - current portion:

    

Directors and affiliates

     508,991        717,833   

Unrelated parties

     250,000        325,000   

Accrued interest expense

     48,359        52,242   

Director fees payable in common stock

     33,615        450   

Accrued consulting services payable in common stock

     42,000        —     

Current portion of asset retirement obligations

     78,140        159,782   

Other accrued costs and expenses

     255,740        57,210   
  

 

 

   

 

 

 

Total Current Liabilities

     2,155,939        1,366,323   
  

 

 

   

 

 

 

Long-Term Liabilities:

    

Contingent acquisition costs payable to DNR Oil & Gas, Inc.

     250,000        250,000   

Notes and advances payable, net of current portion:

    

DNR Oil & Gas, Inc.

     —          792,151   

Directors and affiliates

     —          246,639   

Unrelated parties

     —          425,000   

Asset retirement obligations, net of current portion

     569,128        522,421   
  

 

 

   

 

 

 

Total Long-Term Liabilities

     819,128        2,236,211   
  

 

 

   

 

 

 

Total Liabilities

     2,975,067        3,602,534   
  

 

 

   

 

 

 

Commitments and Contingencies

     —          —     
  

 

 

   

 

 

 

Stockholders’ Equity:

    

Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares:

    

Series 1; authorized 30,000 shares, issued and outstanding 522.5 shares in 2012 and 10 shares in 2013, liquidation preference of $5,420,938 in 2012 and $111,250 in 2013.

     4,987,326        95,451   

Series 2; authorized 2,500 shares, issued and outstanding no shares in 2012 and 2013

     —          —     

Common stock, no par value; authorized 499,000,000 shares, issued and outstanding 7,979,801 in 2012 and 13,608,459 in 2013

     17,151,097        21,488,387   

Accumulated deficit

     (16,227,289     (16,198,862
  

 

 

   

 

 

 

Total Stockholders’ Equity

     5,911,134        5,384,976   
  

 

 

   

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 8,886,201      $ 8,987,510   
  

 

 

   

 

 

 

The Accompanying Notes are an Integral Part of These Financial Statements.

 

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ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

Years Ended December 31, 2012 and 2013

 

     2012     2013  

Revenues:

    

Oil and natural gas sales

   $ 2,255,126      $ 2,225,681   

Royalty revenues

     —          533   

Sale of oil and natural gas properties

     533,048        347,888   
  

 

 

   

 

 

 

Total revenues

     2,788,174        2,574,102   
  

 

 

   

 

 

 

Operating Expenses:

    

Oil and gas producing activities:

    

Lease operating expenses

     824,027        679,172   

Production taxes

     187,756        187,594   

Depreciation, depletion, amortization and accretion

     968,696        665,123   

Gas gathering:

    

Operating expenses

     15,671        14,140   

Depreciation

     44,219        44,219   

General and administrative expenses:

    

Director fees

     63,615        2,250   

Investor relations

     279,775        98,505   

Legal, auditing and professional fees

     191,876        147,348   

Consulting fees executive services:

    

Related parties

     409,000        123,000   

Unrelated parties

     133,186        —     

Other adminstrative expenses

     83,874        59,712   

Depreciation

     570        570   
  

 

 

   

 

 

 

Total operating expenses

     3,202,265        2,021,633   
  

 

 

   

 

 

 

Operating income (loss)

     (414,091     552,469   

Interest income

     226        1   

Interest expense

     (80,190     (132,168
  

 

 

   

 

 

 

Total other income (expense)

     (79,964     (132,167
  

 

 

   

 

 

 

Income (loss) before income taxes

     (494,055     420,302   

Income tax benefit (expense)

     —          —     
  

 

 

   

 

 

 

Net income (loss)

   $ (494,055   $ 420,302   
  

 

 

   

 

 

 

Net Income (Loss) Applicable to Common Stockholders:

    

Net income (loss)

   $ (494,055   $ 420,302   

Redemption of preferred stock

     —          3,160,026   

Accrued Preferred stock dividends

     (783,750     (212,813
  

 

 

   

 

 

 

Net income (loss) applicable to common stockholders

   $ (1,277,805   $ 3,367,515   
  

 

 

   

 

 

 

Earnings (Loss) Per Share Applicable to Common Stockholders:

    

Basic

   $ (0.16   $ 0.31   
  

 

 

   

 

 

 

Diluted

   $ (0.16   $ 0.31   
  

 

 

   

 

 

 

Weighted Average Number of Common Shares Outstanding:

    

Basic

     7,879,000        10,760,000   
  

 

 

   

 

 

 

Diluted

     7,879,000        10,760,000   
  

 

 

   

 

 

 

The Accompanying Notes are an Integral Part of These Financial Statements.

 

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ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2012 and 2013

 

     Class A Preferred Stock     Common Stock      Accumulated        
     Shares     Amount     Shares      Amount      Deficit     Total  

Balances, December 31, 2011

     522.5      $ 5,023,371        7,764,476       $ 16,904,154       $ (14,949,484   $ 6,978,041   

Issuance of common stock for Board of Director’s fees:

              

Valued at $5.20 per share for second quarter of 2011

     —          —          5,769         30,000         —          30,000   

Valued at $3.00 per share for third quarter of 2011

     —          —          10,000         30,000         —          30,000   

Valued at $1.36 per share for fourth quarter of 2011

     —          —          22,058         30,000         —          30,000   

Valued at $1.08 per share for first quarter of 2012

     —          —          27,778         30,000         —          30,000   

Issuance of common stock in exchange for consulting services provided by related parties:

              

Valued at $1.18 per share for April 2012 services

     —          —          50,970         60,000         —          60,000   

Valued at $0.59 per share for May 2012 services

     —          —          85,000         50,000         —          50,000   

Issuance of common stock to unrelated parties:

              

Valued at $1.35 per share for accrued interest

     —          —          7,750         10,463         —          10,463   

Valued at $1.08 per share for consulting services

     —          —          6,000         6,480         —          6,480   

Preferred stock offering costs

     —          (36,045     —           —           —          (36,045

Preferred stock dividends declared and paid

     —          —          —           —           (783,750     (783,750

Net loss

     —          —          —           —           (494,055     (494,055
  

 

 

   

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Balances, December 31, 2012

     522.5        4,987,326        7,979,801         17,151,097         (16,227,289     5,911,134   

Issuance of common stock to unrelated parties:

              

Valued at $0.40 per share for consulting services

     —          —          45,000         18,000           18,000   

Valued at $0.30 per share for consulting services

     —          —          20,000         6,000           6,000   

Valued at $0.30 per share for loan fees

     —          —          20,000         6,000           6,000   

Issuance of common stock in exchange for consulting services provided by related parties:

              

Valued at $0.67 per share for June 2012 services

         44,823         30,000           30,000   

Issuance of common stock for Board of Director’s fees:

              

Valued at an average of $0.49 per share for 2012 and 2013

     —          —          72,170         35,415           35,415   

Conversation of Series A

              

Preferred Stock

     (512.5     (4,891,875     5,426,665         4,241,875           (650,000

Preferred dividend paid

               (391,875     (391,875

Net income

     —          —          —           —           420,302        420,302   
  

 

 

   

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Balances, December 31, 2013

     10.0      $ 95,451        13,608,459       $ 21,488,387       $ (16,198,862   $ 5,384,976   
  

 

 

   

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

The Accompanying Notes are an Integral Part of These Financial Statements.

 

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ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2012 and 2013

 

     2012     2013  

Cash Flows from Operating Activities:

    

Net income (loss)

   $ (494,055   $ 420,302   

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

    

Depreciation, depletion and amortization

     977,864        642,816   

Accretion of discount on asset retirement obligations

     35,621        67,096   

Gain on sale of oil and gas properties

     (533,048     (347,888

Common stock issued in exchange for services

     246,942        18,000   

Common stock issued in exchange for accrued interest

     10,462        —     

Changes in operating assets and liabilities:

    

Accounts receivable

     23,079        (153,519

Prepaid expenses and other

     152,986        22,857   

Accounts payable

     (15,096     (93,136

Accrued costs and expenses

     (49,867     (192,397
  

 

 

   

 

 

 

Net cash provided by operating activities

     354,888        384,131   
  

 

 

   

 

 

 

Cash Flows from Investing Activities:

    

Capital expenditures for oil and gas properties

     (935,322     (307,465

Proceeds from sale of oil and gas properties

     1,108,709        1,033,324   

Contingent consideration paid to DNR under sharing arrangement

     (282,704     (554,193
  

 

 

   

 

 

 

Net cash (used in) provided by investing activities

     (109,317     171,666   
  

 

 

   

 

 

 

Cash Flows from Financing Activities:

    

Proceeds from notes and advance payable

     825,000        1,042,670   

Principal payments on notes payable

     (432,010     (687,190

Payment of dividends on preferred stock

     (783,750     (391,875

Redemption of preferred stock

     —          (50,000

Payment of preferred stock offering costs

     (67,456     —     
  

 

 

   

 

 

 

Net cash used in financing activities

     (458,216     (86,395
  

 

 

   

 

 

 

Net increase (decrease) in cash and equivalents

     (212,645     469,402   

Cash and equivalents, beginning of year

     219,566        6,921   
  

 

 

   

 

 

 

Cash and equivalents, end of year

   $ 6,921      $ 476,323   
  

 

 

   

 

 

 

Supplemental Disclosure of Cash Flow Information:

    

Cash paid for interest

   $ 122,633      $ 117,578   
  

 

 

   

 

 

 

Cash paid for income taxes

   $ —        $ —     
  

 

 

   

 

 

 

Supplemental Disclosure of Non-cash Investing and Financing Activities:

    

Contingent payable for acquisition of oil and gas properties

   $ 250,000      $ —     
  

 

 

   

 

 

 

Asset retirement obligations assumed upon sale of oil and gas properties

   $ 16,411      $ 32,161   
  

 

 

   

 

 

 

Increase in oil and gas properties due to revision of asset retirement obligations

   $ 55,825      $ —     
  

 

 

   

 

 

 

Conversion of Series A1 preferred stock to note payable

   $ —        $ 600,000   
  

 

 

   

 

 

 

The Accompanying Notes are an Integral Part of These Financial Statements.

 

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ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2012 and 2013

 

1. Organization and Nature of Operations

Arête Industries, Inc. (“Arête” or the “Company”), is a Colorado corporation that was incorporated on July 21, 1987. The Company owns 100% of Arête Energy, Inc. which is an inactive subsidiary which has no assets, liabilities or operations. Arête has operated a natural gas gathering system in Wyoming since 2006 and on July 29, 2011 the Company purchased oil & natural gas properties in Colorado, Montana, Kansas, and Wyoming.

The Company seeks to focus on acquiring interests in traditional oil and gas ventures, and seek properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas, which may include shut-in wells, in-field development, stripper wells, re-completion and re-working projects. In addition, the Company’s strategy includes purchase and sale of acreage prospective for oil and natural gas and seeking to obtain cash flow from the sale and farm out of such prospects.

 

2. Summary of Significant Accounting Policies

Use of Estimates

Preparation of the Company’s financial statements in accordance with GAAP requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The most significant areas requiring the use of assumptions, judgments and estimates relate to the volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, impairments of undeveloped properties, and in valuing stock-based payment awards.

The only component of comprehensive income that is applicable to the Company is net income (loss). Accordingly, a separate statement of comprehensive income (loss) is not included in these financial statements.

Principles of Consolidation

The consolidated financial statements of the Company include the accounts of Arête and its inactive subsidiary, Arête Energy, Inc. All intercompany accounts and transactions have been eliminated in consolidation.

Cash Equivalents

For purposes of the statement of cash flows, the Company considers cash and all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Gas Gathering System, Furniture and Equipment

The Company’s gas gathering system and its furniture and equipment are stated at cost. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of normal maintenance and repairs is charged to operating expenses as incurred. Upon disposal of an asset, the cost of the asset and the related accumulated depreciation are removed from the accounts, and any gains or losses will be reflected in current

 

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operations. For the gas gathering system, depreciation is computed using the straight line method over an estimated useful life of ten years. Depreciation of furniture and equipment is computed using the straight-line method over an estimated useful life of five years.

Oil and Gas Producing Activities

The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has proved reserves. If an exploratory well does not result in proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production DD&A rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unevaluated oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage.

The Company reviews its proved oil and gas properties for impairment annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

The provision for DD&A of oil and gas properties is calculated based on proved reserves on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents, BOE, at the rate of six Mcf of natural gas to one barrel of oil. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.

In January 2010, the Financial Accounting Standards Board (“FASB”) issued authoritative oil and gas reserve estimation and disclosure guidance that was effective for the Company beginning in 2010. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC final rule, “Modernization of Oil and Gas Reporting”, which was also effective in 2010. Many of the revisions were updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which was developed by several petroleum industry organizations and is a widely accepted standard for the management of petroleum resources. Key revisions include a requirement to use 12-month average pricing determined by averaging the first of the month prices for the preceding 12 months rather than year-end pricing for estimating proved reserves, the ability to include nontraditional resources in reserves, the ability to use new technology for determining proved reserves, and permitting disclosure of probable and possible reserves.

Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Consolidated Statements of Operations.

 

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Revenue Recognition

The Company records revenues from the sale of natural gas, natural gas liquids (“NGL”) and crude oil when delivery to the purchaser has occurred and title has transferred. The Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company will record revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2012 and 2013 were not material.

Environmental Liabilities

Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2012 and 2013, the Company had not accrued for nor been fined or cited for any environmental violations that would have a material, adverse effect upon capital expenditures, operating results or the competitive position of the Company.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.

Stock-Based Compensation

The Company did not grant any stock options or warrants during the years ended December 31, 2012 and 2013 and no options or warrants were outstanding at any time during these years. The Company has issued shares of common stock for services performed by officers, directors and unrelated parties during 2012 and 2013. The Company has recorded these transactions based on the value of the services or the value of the common stock, whichever is more readily determinable.

Income Taxes

The Company accounts for income taxes under ASC 740. Temporary differences are differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The Company’s temporary differences consist primarily of tax operating loss carry forwards and start-up costs capitalized for tax purposes.

Fair Value of Financial Instruments

Cash, accounts payable, accrued liabilities and notes payable are carried in the Consolidated Financial Statements in amounts which approximate fair value because of the short-term maturity of these instruments.

Earnings Per Share

Basic net income (loss) per share of common stock is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted net income (loss) attributable to common stockholders is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding and other dilutive securities. The only potentially dilutive securities for the diluted earnings per share calculations consist of Series A1 preferred stock that is convertible into common stock at an exchange price of $3.30 per common share. As of December 31, 2013, the convertible preferred stock had an aggregate liquidation preference of $111,250 and was convertible to 33,712 shares of common stock. These shares were excluded from the earnings per share calculation because it was anti-dilutive to assume conversion immediately prior to the last dividend payment date, which would have eliminated preferred dividends for the fourth quarters of 2012 and 2013 from the earnings per share calculation.

 

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New Accounting Pronouncements

In January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-1, Balance Sheet: Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which amended FASB Accounting Standards Codification (“ASC”) Topic 210, Balance Sheet. The main objective in developing this update was to address implementation issues about the scope of ASU 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities. The amendments clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This provision is effective for fiscal years beginning on or after January 1, 2013. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.

In February 2013, the FASB issued ASU 2013-2, Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which amended ASC Topic 220, Comprehensive Income. The objective of this update was to improve the reporting of reclassifications out of accumulated other comprehensive income. The amendment did not change the requirements for reporting net income or other comprehensive income in financial statements. However, the amendment required an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This provision is effective for interim and annual periods beginning after December 15, 2012. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.

In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the Company’s financial statements upon adoption.

 

3. Acquisitions and Dispositions of Oil and Gas Properties

Acquisitions

On May 25, 2011, the Company entered into a Purchase and Sale Agreement and other related agreements and documents with Tucker Family Investments, LLLP; DNR Oil & Gas, Inc. (“DNR”); and Tindall Operating Company (collectively, the “Sellers”) for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana (collectively, the “Original Purchase and Sale Agreement”). DNR is principally owned by an officer and director of the Company, Charles B. Davis. The consideration for the purchase was determined by bargaining between management of the Company and Sellers, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price for the properties was $10.0 million, of which the Company paid a nonrefundable down payment of $0.5 million and the remaining $9.5 million was financed by the Sellers pursuant to a promissory note due on July 1, 2011. The Company was unable to arrange the funding to pay the $9.5 million promissory note due on July 1, 2011, and therefore, the note was not paid.

 

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On July 29, 2011, the Company and Sellers entered into an Amended and Restated Purchase and Sale Agreement (“PSA”) regarding the purchase of (i) working interests in oil and gas properties located in Wyoming, Colorado, Kansas and Montana (the “Properties”), and (ii) vested contractual rights in the net proceeds from the future sale of certain properties located in Wyoming (the “Separate Interests”). The material terms of the PSA included an aggregate base purchase price for the Properties and the Separate Interests of $11.0 million to be paid by an initial payment of $0.9 million, comprised of (i) a credit in the amount of $0.5 million previously paid by the Company in connection with the Original Purchase and Sale Agreement; and (ii) $0.4 million in funds paid contemporaneously with the execution of the PSA. The remaining principal balance of the base purchase price in the amount of $10.1 million, together with interest at 10% per annum, was payable to Sellers in three monthly payments, with $3.7 million due August 15, 2011 (extended to August 31, 2011), and $3.2 million due on each of September 15, 2011 and October 15, 2011. By September 29, 2011, all required consideration had been paid to Sellers and closing of the PSA was completed.

The PSA provided that the Company was entitled to the Properties’ oil and gas production and sales proceeds beginning on April 1, 2011, and the Company was also responsible for the lease operating expenses of the Properties beginning on April 1, 2011. The net proceeds from oil and gas sales, less production taxes and lease operating expenses from April 1, 2011 to July 29, 2011 amounted to $766,728, which was treated as a reduction of the carrying cost of the Properties.

The acquisition of the Properties was structured such that the Company acquired 100% of Seller’s interest in certain geologic zones of the properties. Presented below is a summary of agreed-upon values associated with the Properties and the Separate Interests, along with a discussion of the interests in the Properties retained by the Sellers:

 

Properties:

  

Rex Lake/ Big Hollow (WY)

   $ 511,025 (b) 

Kansas

     2,152,216 (a) 

Montana

     98,179 (b) 

Wyoming

     2,733,773 (b) 

Buff (WY)

     611,211 (b) 

Colorado

     2,507,678 (a) 
  

 

 

 

Total Working Interest Properties

     8,614,082   

Separate Interests

     2,385,918 (d) 
  

 

 

 
   $ 11,000,000 (c) 
  

 

 

 

 

(a) For a period of ten years after the closing date, the Colorado and Kansas properties provide for additional consideration that is payable to Sellers based on increases in Nymex prices for oil and natural gas, without regard to changes in the Company’s oil and natural gas reserves (referred to as the “Price Increase Factor”). If Nymex thresholds of $90, $100, $110, $125 and $150 per barrel of oil are exceeded for periods of 61 consecutive days, incremental purchase consideration of $250,000, $250,000, $500,000, $500,000 and $2,000,000, respectively, will be payable to Sellers. Similarly, if Nymex thresholds of $5.00, $6.00, $7.50, $10.00 and $12.00 per MMbtu of natural gas are exceeded for periods of 61 consecutive days, incremental purchase consideration of $50,000, $50,000, $150,000, $250,000 and $250,000, respectively, will be payable to Sellers.

The Colorado and Kansas properties also provide for additional consideration that is payable to Sellers if reserves classified as “possible” are converted to “proved producing reserves” through drilling or recompletion activities over a period of ten years after the closing date (referred to as the “Possible Reserve Factor”). For such increases in oil reserves, the Sellers are entitled to additional consideration of $250,000 for each increase of 20,000 net barrels; and for such increases in natural gas reserves, the Sellers are entitled to additional consideration of $150,000 for each increase of 150,000 mcf of natural gas.

The Possible Reserve Factor also requires a multiplier effect from 1 to 5 depending on the Price Increase Factor that is effective when the proved producing reserves are obtained. For example, the Possible Reserve Factor consideration would be multiplied by 2 if the oil Price Increase Factor of $100 is in effect when the proved producing reserves are confirmed. Similarly, the Possible Reserve Factor consideration would be multiplied by 2 if a natural gas Price Increase Factor of $6.00 per MMbtu is in effect when the proved producing natural gas reserves are confirmed. The maximum increase in purchase price for the Kansas and Colorado properties is limited to $5 million.

 

(b) Additional consideration is also payable for the properties located in Wyoming to the extent that the Company increases proved producing reserves through future drilling or recompletion activities in formations that are not producing as of the closing date under the Possible Reserve Factor. Similar to the properties in Colorado and Kansas, the Possible Reserve Factor will be multiplied by a factor of 1 to 5 depending on the Price Increase Factor that is effective when the proved producing reserves are obtained.

 

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Furthermore, if the Company sells any of the properties in Wyoming, the Sellers have retained an interest of 70% in the net sales proceeds (after the Company receives a recovery of 125% of the original agreed-upon allocation as contained in the table above).

The maximum increase in purchase price (including Sellers retained interest of 70% for the Wyoming properties discussed in the preceding paragraph) for all properties in all states shown in the table above is limited to $25 million. Due to the sale of the Separate Interests discussed below, accrual of $500,000 due to a sustained increase in oil prices over $90 and $100 per barrel, the sale of a second property in February 2012 and the sale of a third property in 2013, the maximum future consideration has been reduced by approximately $5.8 million to $19.2 million.

 

(c) Note that the values shown in this table are the allocation amounts attributable to the proved developed zones agreed to between the Company and the Sellers, before purchase adjustments for pre-acquisition net revenues received, oil in tanks and contingent purchase price adjustments. These adjustments do not modify the agreed upon value for purposes of the adjustments discussed above but will affect the final purchase allocation under generally accepted accounting principles.

 

(d) With respect to the Separate Interests, a formal closing and transfer of title was not required, and did not occur, in order for the Company to realize its proceeds related to the sale of the Separate Interests. The Company acquired the contractual rights associated with the Separate Interests on July 29, 2011, and the Company’s share of the net proceeds of $5,101,047 was received on August 23, 2011, which resulted in recognition of a non-operating gain in the third quarter of 2011 of $2,479,934. The Company applied the $5,101,047 of net proceeds to the payments due under the PSA.

Property Dispositions

The Company also had an agreement for the right to receive a portion of the proceeds from sale of certain of the properties that could be sold before payment in full of the base purchase price and assignment of the properties to the Company. The School Creek properties were sold on August 23, 2011 and the Company received $5,101,047 for its share of the proceeds on the sale, which resulted in a gain on sale of $2,479,934. The Company applied the proceeds to the payments due under the purchase and sale agreement. On September 29, 2011 the Company paid the balance of $5,120,194 that included $121,241 of interest. The Company as part of the agreement received the production of oil and gas from April 1, 2011 and was responsible was the lease operating expenses for that period. The net proceeds of the production, production taxes, and lease operating expenses from April 1, 2011 to July 29, 2011 of $766,812 was applied to the carrying costs of the oil and natural gas properties.

In February 2012, the Company sold to an unaffiliated party a working interest in a well and related lease in Niobrara County, Wyoming for gross proceeds of approximately $1,109,000. After payment of additional consideration pursuant to the formula discussed under (b) in the acquisition table above, the Company realized net proceeds of $826,000. The purchaser assumed the asset retirement obligations estimated at approximately $16,000 and after deducting the net book value of the property, the Company recognized a gain on sale of $533,048. The Company retained a 2.575% overriding royalty interest in this property. This sale comprised approximately 1.6% of the Company’s barrels of oil equivalent (“BOE”) of oil and gas reserve quantities, and approximately 2.2% of the Company’s discounted future net revenues prior to the sale. The Company determined that this sale did not qualify for discontinued operations reporting.

In December 2013, we sold one of our producing properties, which resulted in gross proceeds of approximately $1,004,000. This property was sold to an unrelated purchaser and pursuant to our amended purchase agreement entered into in September 2013, we were required to pay the related party sellers approximately $554,000 of the proceeds due to their contingent interest and, as a result our net proceeds were $450,000. After deducting the net book value of the property of $163,000, plus the asset retirement obligation assumed by the unrelated purchaser of $31,000, we recognized a gain of approximately $318,000. The Company retained a 1.57% overriding royalty interest in this property. This sale comprised approximately 1.1% of the Company’s barrels of oil equivalent (“BOE”) of oil and gas reserve quantities, and approximately 2.2% of the Company’s discounted future net revenues prior to the sale. The Company determined that this sale did not qualify for discontinued operations reporting.

 

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4. Stockholders’ Equity

Common Stock

In June 2012, the Company issued an aggregate of 215,325 shares of common stock in satisfaction of previously accrued liabilities as follows:

 

     Number of
Shares
     Valuation
Price
     Amount  

Board of Director fees:

        

Fees for second quarter of 2011

     5,769       $ 5.20       $ 30,000   

Fees for third quarter of 2011

     10,000       $ 3.00         30,000   

Fees for fourth quarter of 2011

     22,058       $ 1.36         30,000   

Fees for first quarter of 2012

     27,778       $ 1.08         30,000   

Related party executive, administrative & operational services

        

Fees for January 2012

     11,538       $ 1.30         15,000   

Fees for February 2012

     12,500       $ 1.20         15,000   

Fees for March 2012

     13,890       $ 1.08         15,000   

Fees for April 2012

     13,042       $ 1.15         15,000   

Related party consulting services in June 2012

     85,000       $ 0.59         50,000   

Accrued interest on unrelated party notes payable

     7,750       $ 1.35         10,463   

Unrelated party consulting

     6,000       $ 1.08         6,480   
  

 

 

       

 

 

 

Total

     215,325       $ 0.59       $ 246,943   
  

 

 

       

 

 

 

Board of Directors fees are payable quarterly in common stock based on the closing price at the end of each quarter. Through the second quarter of 2012, each of the Company’s five directors earned a monthly fee of $2,000 for an aggregate of $30,000 per quarter. In June 2012, an aggregate of 65,605 shares were issued for director fees incurred in the second quarter of 2011 through the first quarter of 2012. Beginning in the third quarter of 2012, directors are entitled to 300 shares of the Company’s common stock for each meeting attended. Each of the Company’s five directors attended six meetings in the second half of 2012 resulting in an obligation for the Company to issue an aggregate of 9,000 shares with an estimated fair value of $3,615.

From January 2012 through July 2012, the Board of Directors agreed to pay fees for executive, administrative and operational services in the aggregate amount of $15,000 per month to three individuals who are directors and/or stockholders of the Company. These fees are payable in shares of the Company’s common stock based on the closing price on the last day of the month for which the services are performed. In June 2012, the Company issued an aggregate of 50,970 shares of common stock in satisfaction of this obligation for the months of January through April 2012. The Company has not yet settled the liabilities for services performed in May through July 2012, but management expects to issue 44,823 shares of the Company’s common stock valued at $0.67 per share to settle the remaining liability for $30,000.

In June 2012, the Board of Directors approved the issuance of 85,000 shares of common stock for consulting services provided by an individual that owns preferred stock of the Company. The services were valued based on the closing price of the Company’s common stock on the date of board approval which was $0.59 and resulted in a charge to related party consulting fees of $50,000.

As of December 31, 2012, the Company has a liability for directors’ fees of $33,615 which is expected to result in the issuance of 64,556 shares of common stock in 2013. Additionally, the Company has a liability for accrued consulting fees of $29,550 which is expected to result in the issuance of 85,000 shares of common stock in 2013.

During the year ended December 31, 2013, the Company issued 45,000 shares of common stock for payment of fees accrued to a consultant. The Company issued 84,823 shares of common stock for payment of fees accrued to related party consultants. The Company issued 72,170 shares of common stock for payment of accrued directors fees for the period July 1, 2012 to November 30, 2013.

 

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Effective June 28, 2013, several holders of the Company’s 15% Series A1 Convertible Preferred Stock (“Series A1 Preferred Stock”) elected to convert shares of such stock into the Company’s common stock at a redemption price of $0.75 per common share. In connection with those redemptions all such holders agreed to waive all dividend rights on their shares of Series A1 Preferred Stock subsequent to March 30, 2013. Information regarding the conversions is set forth below.

 

Name of Holder

   Number of Shares of Series
A1 Preferred Stock Converted
   Number of
Common Shares Issued
 

Burlingame Equity Investors II, LP

   16      100,800   

Burlingame Equity Investors Master Fund, LP

   184      1,159,200   

Charles B. Davis*

   100      1,333,333   

Tucker Family Investments LLLP

   25      333,333   

Mark Venjohn

   10      133,333   

Pete Haman

   35      466,667   

Nicholas L. Scheidt*

   100      1,333,333   

Michael J. Finney

   5      66,667   

William and Sara Kroske

   2.5      33,333   

Michael A. Geller

   10      133,333   

John H. Rosasco

   10      133,333   

Lyon Oil & Gas Company

   10      133,333   

T P Furlong

   5      66,667   

 

* Executive Officer and Director of the Company

In addition, in connection with the conversions of Series A1 Preferred Stock by Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP, the Company also entered into transactions with these entities in exchange for cash consideration, promissory notes and cancellation of certain Series A1 Preferred Shares.

 

Name of Holder

   Cash Consideration      Promissory
Note – Principal
     Series A1 Preferred
Shares Cancelled

Burlingame Equity Investors II, LP

   $ 4,000       $ 48,000       16

Burlingame Equity Investors Master Fund, LP

   $ 46,000       $ 552,000       184

The above promissory notes bear interest at 7% per annum, with interest payable quarterly and all unpaid interest and principal due on July 23, 2014. If the promissory notes are not paid when due or declared due, the entire principal and interest thereon will bear interest at the rate of 12% per annum (see note 5).

The redemption of preferred stock on the earning per share applicable to common stockholders was calculated as the difference between the fair market value of common shares received on June 28, 2013 and the cost of the preferred stock redeemed which amounted to $3,160,026.

Preferred Stock Dividends

Preferred stock dividends are payable semi-annually in cash or shares of the Company’s common stock, at the election of the Company. During 2012, the Board of Directors declared and paid an aggregate of $783,750 for the 15% semi-annual dividend on the Series A1 preferred stock. As of December 31, 2012, accrued dividends amounted to $195,938 which is excluded from liabilities until formally declared by the Company’s Board of Directors. The Board of Directors declared the preferred dividend of $391,875 on April 26, 2013 and paid the dividend in cash on April 28, 2013.

Preferred Stock

On September 29, 2011, the Company completed a private placement of its Preferred Stock Series A1 which resulted in the issuance of 522.5 shares for gross proceeds of $5,225,000. The balance of the Preferred Stock Series A1 at December 31, 2013 is 10 shares and $95,451. The following are the terms of the Preferred Stock Series A1:

Authorized Shares, Stated Value and Liquidation Preference. Seven hundred fifty shares are designated as the Series A1 15% Convertible Preferred Stock, which has a stated value and liquidation preference of $10,000 per share plus accrued and unpaid dividends.

Ranking. The Series A1 Preferred Stock will rank senior to future classes or series of preferred stock established after the issue date of the Series A1 Preferred Stock, unless the Company’s Board of Directors expressly provides otherwise when establishing a future class or series. The Series A1 Preferred Stock ranks senior to the Company’s common stock in liquidation and dissolution.

 

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Dividends. Holders of Series A1 Preferred Stock are entitled to receive, when, as and if declared by the Board of Directors, non-cumulative dividends at an annual rate of 15.0% of the $10,000 per share stated value. Declared dividends are payable in cash or in shares of Common Stock (at its then fair market value), at the election of the Company.

Voting Rights. The holders of the Series A1 Preferred Stock will vote together with the holders of common stock as a single class on all matters upon which the holders of common stock are entitled to vote, except that the common stock will elect four directors and the Series A1 Preferred Stock will elect three directors. Each share of Series A Preferred Stock will be entitled to such number of votes as the number of shares of common stock into which such share of Preferred Stock is convertible; however, solely for the purpose of determining such number of votes, the conversion price per share will be deemed to be $3.30, subject to customary anti-dilution adjustment. In addition, the holders of the Series A1 Preferred Stock will vote as a separate class with respect to certain matters, including amendments to the Company’s Articles of Incorporation that alter the voting powers, preferences and special rights of the Series A1 Preferred Stock.

Liquidation. In the event we voluntarily or involuntarily liquidate, dissolve or wind up, the holders of the Series A1 Preferred Stock will be entitled, before any distribution or payment out of the Company’s assets may be made to or set aside for the holders of any junior capital stock and subject to the rights of creditors, to receive a liquidation distribution in an amount equal to $10,000 per share, plus any accrued but unpaid dividends. A merger, consolidation or sale of all or substantially all of the Company’s property or business is not deemed to be a liquidation for purposes of the preceding sentence.

Redemption. The Series A1 Preferred Stock is redeemable in whole or in part at the Company’s option at any time. The redemption price is equal to $10,000 per share, plus any accrued but unpaid dividends.

Preemptive Rights. Holders of the Series A1 Preferred Stock do not have preemptive rights to purchase securities of the Company.

Mandatory Conversion. Each share of Series A1 Preferred Stock remaining outstanding will automatically be converted into shares of our common stock upon the earlier of (i) any closing of underwritten offering by the Company of shares of Common Stock to the public pursuant to an effective registration statement under the Securities Act of 1933, in which the aggregate cash proceeds to be received by the Company and selling stockholders (if any) from such offering (without deducting underwriting discounts, expenses and commissions) are at least $15,000,000, and the price per share paid by the public for such shares is at least $3.30 (such price to be adjusted for any stock dividends, combinations or splits or (ii) the date agreed to by written consent of the holders of a majority of the outstanding Series A1 Preferred Stock.

Optional Conversion by Investors. At any time, each holder of Series A1 Preferred Stock has the right, at such holder’s option, to convert all or any portion of such holder’s Series A1 Preferred Stock into shares of common stock prior to the mandatory conversion of the Series A1 Preferred Stock at a price of $3.30 per share.

Optional Conversion by the Company. If the closing price of the Company’s common stock on the Trading Market is $4.50 or more for 20 consecutive trading days, then up to 25% of the outstanding stated value of the Series A1 Preferred Stock, plus any accrued and unpaid dividends, will be subject to conversion into Company common stock at the option of the Company. For each successive period that the closing price of the common stock is at least $4.50 for a period of 20 consecutive trading days beyond the first 20 day period, the Company will have the right to convert another 25% of the outstanding Series A1 Preferred Stock, such that if the closing price of the common stock is at least $4.50 for 80 consecutive trading days, then all of the outstanding shares of Series A1 Preferred Stock may be converted into common stock at the Company’s option.

Conversion Price. Each share of Series A1 Preferred Stock is convertible into shares of common stock at a conversion price of $3.30 per share, subject to customary anti-dilution adjustments, including in connection with stock dividends and distributions, stock splits, subdivisions and combinations.

Redemption by Holder. Unless prohibited by Colorado law, upon 90 days’ prior written request from any holders of outstanding shares of Series A1 Preferred Stock, the Company may at its discretion, redeem at a redemption price equal to the sum of (i) $10,000 per share and (ii) the accrued and unpaid dividends thereon, to the redemption date, up to one-third of each holder’s outstanding shares of Series A1 Preferred Stock on: (i) the first anniversary of the Original Issuance Date (the “First Redemption Date”), (ii) the second anniversary of the Original Issue Date (the “Second Redemption Date”) and (iii) the third anniversary of the Original Issue Date (the “Third Redemption Date”, along with the First Redemption Date and the Second Redemption Date, collectively, each a “Redemption Date”). The redemption price for any shares of Series A1 Preferred Stock shall be payable on the redemption date to the holder of such shares against surrender of the certificate(s) evidencing such shares to the Corporation or its agent. The Company may instead at its option, reduce the applicable conversion price by 50% with respect to the shares of preferred stock for which redemption has been requested.

 

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5. Notes and Advances Payable

Notes payable consist of the following as of December 31, 2012 and 2013

 

     2012      2013  

Officers, directors and affiliates:

     

Notes and advances payable, interest at 8.0%, due on demand

   $ 12,882       $ 14,984   

Notes and advances payable, interest at 9.7%, due on demand

     85,000         85,000   

Note payable, interest at 12.0%, due March 2015

     150,000         150,000   

Collateralized note payable (see below)

     261,109         714,488   
  

 

 

    

 

 

 

Total officers, directors and affiliates

     508,991         964,472   

Less: Current portion of officers, directors, and affiliates

     508,991         717,833   
  

 

 

    

 

 

 

Long-term portion of officers, directors, and affiliates

   $ —         $ 246,639   
  

 

 

    

 

 

 

Unrelated parties:

     

Notes payable, interest at 7.5%, due March 2015

     250,000         200,000   

Notes payable, interest at 7.0%, due January 2015

     —           44,000   

Notes payable, interest at 7.0%, due January 2015

     —           506,000   
  

 

 

    

 

 

 

Total unrelated parties

     250,000         750,000   

Less: Current portion of unrelated parties

     250,000         325,000   
  

 

 

    

 

 

 

Long-term portion of unrelated parties

   $ —         $ 425,000   
  

 

 

    

 

 

 

On September 29, 2012, the Company borrowed $425,000 from an affiliate of a stockholder and director under a note agreement that provides for interest at the stated annual rate of 12% (and an effective annual rate of 17.8%) with unpaid principal and interest due on March 29, 2013. The outstanding principal balance as of March 31, 2013 was $261,109 and was paid in full April 29, 2013.

On April 29, 2013, the Company executed a promissory note under which the Company agreed to pay Apex Financial Services Corp, a Colorado corporation, (“Apex”) the principal sum of $1,000,000, with interest accruing at an annual rate of 7.5%, with principal and interest due on May 31, 2014. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other assets sales to Apex to secure the debt. Apex is 100% owned by the CEO, director, and shareholder of the Company, Nicholas L. Scheidt. The Company borrowed the full amount of principal on the note, and also paid a loan fee of $10,000. In the event of default on the note and failure to cure the default in ten days, Apex may accelerate payment and the annual interest rate on the note will accrue at 18%. Default includes failure to pay the note when due or if the Company borrows any other monies or offers security in the Company or in the collateral securing the note prior to the note being paid in full. The outstanding principal balance as of December 31, 2013 was $714,488.

All of the notes payable shown above are unsecured, except the Apex note. Accrued interest on notes and advances payable amounted to $48,359 as of December 31, 2012 and $52,242 as of December 31, 2013.

Effective January 1, 2014 the Company restructured its debt with DNR Oil & Gas, Inc., the amount owed to DNR Oil & Gas, Inc. of $792.151 all became long-term. (Note 12)

 

6. Contracts Payable

The Company entered into a consulting contract for financing, structure, and investor services on March 2, 2010 for 800,000 shares of Common Stock valued at $500,000, or $0.625 per share. The contract is for a period of three years and is being amortized ratably over the service period. For each of the years ended December 31, 2012 and 2013, $166,667 and $27,778 related to this consulting contract is included in investor relations expense in the accompanying Consolidated Statements of Operations.

 

7. Cost Reductions

In connection with the property acquisition agreement entered into in the third quarter of 2011, the Company executed an operating agreement whereby DNR provides services to operate all of the properties acquired by the Company for a monthly fee of $23,000. The operating agreement expired on March 31, 2012 and renews on a month to month basis. Based on operator costs for the properties prior to the Company’s acquisition, approximately $8,000 per month is included

 

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in lease operating expenses and $15,000 per month is included in related party consulting fees in the accompanying Consolidated Statements of Operations. Effective July 1, 2012, the monthly operator fee was reduced to $18,000 per month, of which $8,000 per month is included in lease operating expense and the remaining $10,000 per month is included in related party consulting fees.

Presented below is a summary of general and administrative expenses for the years ended December 31, 2012 and 2013:

 

     2012      2013      Change  

Director fees

   $ 63,615       $ 2,250       $ (61,365

Investor relations

     279,775         98,505         (181,270

Legal, auditing and professional services

     191,876         147,348         (44,528

Consulting and executive services:

        

Related parties

     409,000         123,000         (286,000

Unrelated parties

     133,186         —           (133,186

Other administrative expenses

     83,874         59,712         (24,162

Depreciation

     570         570         —     
  

 

 

    

 

 

    

 

 

 

Total general and administrative expenses

   $ 1,161,896       $ 431,385       $ (730,511
  

 

 

    

 

 

    

 

 

 

General and administrative expenses decreased by $730,511 for 2013 compared to 2012, primarily due to decreases in investor relations of $181,270; director fees of $61,365; legal, auditing and professional fees of $44,528; and consulting and executive services (related and unrelated parties) of $419,186.

 

8. Income Taxes

At December 31, 2013, the Company has net operating loss (“NOL”) carryforwards for Federal income tax purposes of approximately $7,900,000. If not previously utilized, the NOL carryforwards will expire in 2015 through 2032.

For the years ended December 31, 2012 and 2013, the Company did not recognize any current or deferred income tax benefit or expense. Actual income tax benefit (expense) for the years ended December 31, 2012 and 2013 differs from the amounts computed using the federal statutory tax rate of 34%, as follows:

 

     2012     2013  

Income tax benefit (expense) at the statutory rate

   $ 168,000      $ (152,000

Benefit (expense) resulting from:

    

Increase in Federal valuation allowance

     (168,000     —     

Utilization of net operating loss carryforwards

     —          152,000   
  

 

 

   

 

 

 

Income tax benefit (expense)

   $ —       $ —    
  

 

 

   

 

 

 

At December 31, 2012 and 2013, the tax effects of temporary differences that give rise to significant deferred tax assets and liabilities are presented below:

 

     2012     2013  

Federal net operating loss carryforwards

   $ 2,811,000      $ 2,677,000   

State net operating loss carryforwards

     286,000        268,000   

Oil and gas properties

     (222,000     (222,000

Asset retirement obligations

     241,000        241,000   
  

 

 

   

 

 

 

Net deferred tax assets

     3,116,000        2,964,000   

Less valuation allowance

     (3,116,000     (2,964,000
  

 

 

   

 

 

 

Net deferred tax assets

   $ —       $ —    
  

 

 

   

 

 

 

A valuation allowance has been recorded for all deferred tax assets since the “more likely than not” realization criterion was not met as of December 31, 2012 and 2013.

 

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A tax benefit from an uncertain tax position may be recognized if it is “more likely than not” that the position is sustainable based solely on its technical merits. For the years ended December 31, 2012 and 2013, the Company had no unrecognized tax benefits and management is not aware of any issues that would cause a significant increase to the amount of unrecognized tax benefits within the next year. The Company’s policy is to recognize any interest or penalties as a component of income tax expense. The Company’s material taxing jurisdictions are comprised of the U.S. federal jurisdiction and the states of Colorado, Wyoming and Kansas. The tax years 2008 through 2013 remain open to examination by these taxing jurisdictions.

 

9. Asset Retirement Obligations

The Company follows accounting for asset retirement obligations (“ARO”) in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value can be made. The Company’s ARO primarily represents the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its ARO by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The ARO is accreted to its present value each period and the capitalized asset retirement costs are amortized using the unit of production method.

A reconciliation of the Company’s ARO for the years ended December 31, 2012 and 2013 is as follows:

 

     2012     2013  

Balance, beginning of year

   $ 653,240     $ 647,268   

Liabilities incurred upon acquisition of properties

     —          —     

Liabilities assumed by buyer of properties

     (16,411 )     (32,161

Liabilities settled

     (81,007     —     

Accretion expense

     35,621        67,096   

Revisions of prior estimates

     55,825       —     
  

 

 

   

 

 

 

Balance, end of year

     647,268        682,203   

Less current asset retirement obligations

     (78,140     (159,782
  

 

 

   

 

 

 

Long-term asset retirement obligations

   $ 569,128      $ 522,421   
  

 

 

   

 

 

 

 

10. Commitments and Contingencies

Lease commitments. The Company entered into a lease for property access rights and compressor space in Wyoming related to the Company’s natural gas gathering system. The expense in 2012 and 2013 was approximately $9,600, which is included in gas gathering operating costs. The Company uses office space and conference room space provided by a director for an annual charge of $3,000 for the years ended December 31, 2012 and 2013.

Legal Proceedings. The Company is subject to the risk of litigation, claims and assessments that may arise in the ordinary course of its business activities, including contractual matters and regulatory proceedings. As of December 31, 2013, the Company was not subject to any pending litigation and management is not currently aware of any asserted or unasserted claims and assessments that may impact the Company’s future results of operations.

 

11. Business and Credit Concentrations

Concentrations of Market Risk. The future results of the Company’s oil and gas operations will be affected by the market prices of oil and gas. A readily available market for crude oil, natural gas and liquid products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and liquid products, the regulatory environment, the economic environment and other regional and political events, none of which can be predicted with certainty.

 

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The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from DNR, a related party that operates the Company’s oil and gas properties and collects remittances from the purchasers of the Company’s oil and natural gas. The Company believes that no single customer or joint venture partner exposes the Company to significant credit risk. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the natural gas or oil industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations in the long-term. Trade receivables are not collateralized.

Concentrations of Credit Risk. The Company maintains its cash in bank accounts that, at times, may exceed federally insured limits. At December 31, 2013, the Company had approximately $1,076,000 of cash in bank accounts that exceeded the $250,000 federally insured limit. The difference between this amount and the amount of cash and equivalents shown in the 2013 consolidated balance sheet is primarily attributable to outstanding checks. The Company has not experienced any losses related to investments in cash and equivalents.

 

12. Subsequent Events

A) The Company restructured its debt the terms are as follows:

Bank Line of Credit

On January 28, 2014, we entered into a line of credit loan agreement for $1,500,000 due January 28, 2015. The terms of the note are as follows: 1) the accrued interest is payable monthly starting February 28, 2014, 2) the interest rate is variable based on an index calculated based on a prime rate as published by the Wall Street Journal index (currently 3.25%) plus an add on index with the current and minimum rate of 6.5%., 3) the note has draw provisions, with the first draw of $479,701, 4) the note is secured by seven wells and leases owned by the Company, a certificate of deposit for $500,000 at CityWide Bank pledged by a third party, and 5) the personal guarantee of the Nicholas Scheidt, Chief Executive Officer. The amount eligible for borrowing on the Credit Facility is limited to the lesser of (i) 65% of the Company’s PV10 value of its carbon reserves based upon the most current engineering reserve report or (ii) 48 month cumulative cash flow based upon the most current engineering reserve report. In addition to the borrowing base limitation, the Company is required to maintain and meet certain affirmative and negative covenants and conditions in order to draw advances on the Credit Facility. The Credit Facility contains certain representations, warranties, and affirmative and negative covenants applicable to the Company, which are customarily applicable to senior secured loan facilities. Key covenants include limitations on indebtedness, restricted payments, creation of liens on oil and gas properties, hedging transactions, mergers and consolidations, sales of assets, use of loan proceeds, change in business, and change in control. The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 21% per annum. In addition, the Credit Facility contains customary events of default, including: (a) failure to pay any obligations when due; (b) failure to comply with certain restrictive covenants; (c) false or misleading representations or warranties; (d) defaults of other indebtedness; (e) specified events of bankruptcy, insolvency or similar proceedings; (f) one or more final, non-appealable judgments in excess of $50,000 that is not covered by insurance; (g) change in control (25% threshold); (h) negative events affecting the Guarantor; and (i) lender in good faith believes itself insecure. In an event of default arising from the specified events, the Credit Facility provides that the commitments thereunder will terminate and the Lender may take such other actions as permitted including, declaring any principal and accrued interest owed on the line of credit to become immediately due and payable. The Credit Facility is secured by a security interest in substantially all of the assets of the Company, pursuant to a Security Agreement, Deed of Trust and Assignment of As-Extracted Collateral entered into between the Company and Citywide Banks.

 

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Related Party Notes Payable

On January 1, 2014, we memorialized our short-term liabilities into formal promissory notes. These certain outstanding advances and other notes payable are now included in single promissory notes, all have been reported previously in our financial statements. Information concerning these promissory notes is set forth in the table below.

 

Name of Holder

  

Position

   Principal
Amount
     Interest
Rate
    Monthly
P&I
Payment
Amount
     Number
of
Monthly
Payments
 

Donald W. Prosser

   CFO & Director    $ 28,500         7.00   $ 564.33         60   

Charles B. Davis

   COO & Director    $ 66,500         7.00   $ 1,316.78         60   

William Stewart

   Director    $ 49,500         7.00   $ 980.16         36   

The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 18% per annum.

In addition, we also issued an unsecured promissory note in the amount of $792,151 on January 1, 2014 to DNR Oil & Gas, Inc. (“DNR”) to restructure its existing debt. DNR is a company controlled by one of our directors, Charles B. Davis. The DNR note accrues interest at the rate of 2.50% for the calendar years 2014 and 2015, 4.00% for the calendar year 2016, 6.00% for the calendar year 2017 and 8.00% for the remainder of the term of the DNR note. The DNR note matures on January 1, 2019. The DNR note requires payments as follows:

 

    One payment of $250,000 in 2016;

 

    One payment of $250,000 in 2017;

 

    One payment of $250,000 in 2018; and

 

    The balance of principal and accrued interest on or before January 1, 2019.

The DNR note contains customary default and acceleration provisions and provides for a default interest rate of 18% per annum. The DNR note is subordinate to the bank line of credit.

Extension of Existing Promissory Notes

In June 2013, in connection with the conversions of Series A1 Preferred Stock by Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP, the Company issued unsecured promissory notes in the original principal amounts of $48,000 and $552,000, respectively, with interest at 7% per annum payable quarterly and all unpaid interest and principal due on July 23, 2014. In connection with our new line of credit, we have agreed with the holders of these two existing notes to make a partial prepayment on the principal balance of the Notes in exchange for an extension of the maturity date to January 27, 2015. Information concerning the principal pay down and new maturity date is set forth in the following table.

 

Name of Holder

   Principal Balance
Before Pay down
     Principal
Pay down
     Remaining
Principal
Balance
 

Burlingame Equity Investors II, LP

   $ 44,000       $ 17,511       $ 26,489   

Burlingame Equity Investors Master Fund, LP

   $ 506,000       $ 232,489       $ 273,511   

 

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B) Wyoming Well Participations:

The Company has participated as a working interest owner in three horizontal wells to be drilled in Campbell County, Wyoming in the Turner zone.

The following is a description of the wells.

 

  4) The Thielen #1-21 is in Section 21 Township 43N. This well is currently being drilled to a total depth of approximately 15,350 including the lateral. The Company will have an approximate 1.06% working interest.

 

  5) The Thielen #2-21 is in Section 21 Township 43N. This well is scheduled to be drilled in the summer of 2014 and is planned to be drilled to a total depth of approximately 15,330 feet including the lateral. The Company will have an approximate 1.06% working interest.

 

  6) The Starlight Federal 28H is located in Section 7, Township 43N. This well is scheduled to be drilled in the first quarter of 2014 and is planned to be drilled to a total depth of approximately 15,310 including the lateral. The Company will have an approximate 0.7025% working interest.

The Company has not received any results on the wells other then the drilling has been completed and the information is being evaluated.

C) The Company agreed to repurchase 1,200,000 shares of its Common Stock. The following are the details of the transaction:

On December 10, 2013, Burlingame Equity Investors Master Fund LP (“Burlingame”), a significant stockholder of Arête Industries, Inc. (the “Company”) entered into conditional stock option agreements with Nicholas L. Scheidt, the Company’s Chief Executive Officer and Director, pursuant to which Mr. Scheidt was granted options to purchase up to 1,460,000 shares of Company common stock at $0.19 per share. Mr. Scheidt subsequently assigned the right to purchase 1,200,000 shares to the Company on January 27, 2012. On January 30, 2014, the Company entered into a Direct Stock Purchase Agreement with Burlingame pursuant to which the Company has purchased the 1,200,000 shares of its common stock from Burlingame at a price of $0.19 per share for total consideration of $228,000. In addition, Mr. Scheidt assigned an additional 141,873 shares of Company common stock underlying his option from Burlingame to Donald W. Prosser, the Company’s Chief Financial Officer and Director. Pursuant to this assignment, Mr. Prosser has agreed to purchase the entire 141,873 shares of Company common stock from Burlingame at a price of US $0.19 per share for total consideration of $26,956. Furthermore, of these 141,873 shares, Mr. Prosser has agreed to transfer 57,895 shares to William W. Stewart, a Director of the Company, for $11,000 or $0.19 per share and 13,158 shares to Apex Financial Services Corp, a company controlled by Mr. Scheidt, for $2,500 or $0.19 per share. Finally, Mr. Scheidt has agreed to exercise the remaining 118,127 shares of Company common stock under his option from Burlingame at a price of $0.19 per share for total consideration of $22,444.

 

 

14. Supplementary Oil and Gas Information (unaudited)

Costs Incurred in Oil and Gas Producing Activities

Costs incurred in oil and gas property acquisition exploration and development activities and related depletion, depreciation, amortization and accretion (“DD&A”) per equivalent unit-of-production were as follows for the years ended December 31, 2012 and 2013:

 

     2012      2013  

Acquisition costs:

     

Unproved properties

   $ —         $ —     

Proved properties

     296,114         —     

Exploration costs

     —          —    

Development costs

     325,034         307,834   

Revisions to asset retirement obligations

     55,825         34,934   
  

 

 

    

 

 

 

Total costs incurred

   $ 676,973       $ 342,768   
  

 

 

    

 

 

 

Depletion per BOE of production

   $ 24.08       $ 19.01   
  

 

 

    

 

 

 

 

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Supplemental Oil and Gas Reserve Information

The reserve information presented below is based on estimates of net proved reserves as of December 31, 2012 and 2013 that were prepared by Ryder Scott Company, the Company’s independent petroleum engineering firm, in accordance with guidelines established by the SEC.

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Changes in Proved and Probable Reserves

The following table sets forth information regarding the Company’s estimated total proved and Probable and oil and gas reserve quantities for the years ended December 31, 2012 and 2013:

 

     Oil
(Bbl)
    Gas
(Mcf)
    Equivalent
(BOE)
 

Balance, December 31, 2011

     375,018       872,301       512,902  

Sale of oil and gas reserves in place

     (7,950     —          (7,950

Revisions in previous estimates

     (10,040     (253,859     (44,850

Production

     (25,356     (89,203     (40,223
  

 

 

   

 

 

   

 

 

 

Balance, December 31, 2012

     331,672        529,239        419,879   

Sale of oil and gas reserves in place

     (4,080     —         (4,080

Revisions in previous estimates

     (60,081     223,116        (18,229

Production

     (20,517     (85,567     (37,778
  

 

 

   

 

 

   

 

 

 

Balance, December 31, 2013

     246,994        676,788        359,792   
  

 

 

   

 

 

   

 

 

 

Proved reserves, December 31, 2012:

      

Proved developed

     255,264        529,239        343,471   
  

 

 

   

 

 

   

 

 

 

Proved undeveloped

     76,408        —          76,408   
  

 

 

   

 

 

   

 

 

 

Proved reserves, December 31, 2013:

      

Proved developed

     184,349        668,489        295,764   
  

 

 

   

 

 

   

 

 

 

Proved undeveloped

     62,645        8,299        64,028   
  

 

 

   

 

 

   

 

 

 

Probable Reserves, December 31, 2012

     6,705        —          6,705   
  

 

 

   

 

 

   

 

 

 

Probable Reserves, December 31, 2013

     8,800        3,223        9,337   
  

 

 

   

 

 

   

 

 

 

Standardized Measure

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

As of December 31, 2012, future cash inflows were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December of 2012, which resulted in benchmark prices of $94.71 per barrel for crude oil and $2.76 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2012 of $81.33 per barrel of oil and $5.46 per Mcf for natural gas.

 

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As of December 31, 2013, future cash inflows were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December of 2013, which resulted in benchmark prices of $96.78 per barrel for crude oil and $3.67 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2013 of $87.49 per barrel of oil and $5.86 per Mcf for natural gas.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Net operating losses incurred in oil and gas producing activities are utilized to reduce taxable income. Permanent differences in oil and gas related tax credits and allowances are recognized, if reasonably estimable.

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves as of December 31, 2012 and 2013:

 

     2012     2013  

Future cash inflows

   $ 29,863,700      $ 25,573,856   

Future production costs

     (13,170,117     (10,493,071

Future development costs

     (862,692     (880,485

Future income taxes

     (2,911,225     (2,490,706
  

 

 

   

 

 

 

Future net cash flows

     12,919,666        11,709,594   

10% annual discount

     (5,886,476     (5,554,947
  

 

 

   

 

 

 

Discounted future net cash flows

   $ 7,033,190      $ 6,154,647   
  

 

 

   

 

 

 

The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on average prices realized in the preceding year and on costs in effect at the end of the year. However, actual future net cash flows from the Company’s oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas and changes in governmental regulations or taxation.

The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows 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 gas industry in general.

 

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A summary of changes in the standardized measure of discounted future net cash flows is as follows for the years ended December 31, 2012 and 2013:

 

     2012     2013  

Standardized measure of discounted future net cash flows, beginning of year

   $ 8,342,000      $ 7,033,190   

Sales of oil and gas, net of production costs and taxes

     (1,243,343     (1,359,448

Purchases of reserves in place

     —          —     

Sales of reserves in place

     (238,347     (160,748

Changes in development costs

     129,194        (7,872

Revisions of previous estimates

     (1,013,042     (524,566

Changes in prices and production costs

     (729,103     492,325   

Net changes in income taxes

     951,631        (21,553

Accretion of discount

     834,200        703,319   
  

 

 

   

 

 

 

Standardized measure of discounted future net cash flows, end of year

   $ 7,033,190      $ 6,154,647   
  

 

 

   

 

 

 

 

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable.

Item 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2013, our Chief Executive Officer and Chief Financial Officer (the “Certifying Officers”) conducted evaluations of our disclosure controls and procedures. As defined under Sections 13a-15(e) and 15d-15(e) of the Exchange Act, the term “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including the Certifying Officers, to allow timely decisions regarding required disclosure. Based on this evaluation, the Certifying Officers have concluded that our disclosure controls and procedures were not effective to ensure that material information is recorded, processed, summarized and reported by our management on a timely basis in order to comply with the disclosure requirement under the Exchange Act and the rules and regulations promulgated thereunder.

Management’s Report on Internal Control Over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act, as amended. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. We have identified the following material weaknesses.

 

    Our Board of Directors does not currently have any independent members that qualify as an audit committee financial expert,

 

    We have not developed and effectively communicated our accounting policies and procedures, and

 

    Our controls over financial statement disclosures were determined to be ineffective.

Changes in Internal Control Over Financial Reporting.

The annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit smaller reporting companies to provide only management’s report in this annual report.

There have been no changes in our internal control over financial reporting during the latest fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. OTHER INFORMATION

Not Applicable.

 

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The directors named below were elected for one-year terms. Officers hold their positions at the discretion of the Board of Directors absent any employment agreements, none of which currently exist or are contemplated. The names, addresses and ages of each of our directors and executive officers and the positions and offices held by them, which director positions are for a period of one year, are:

 

Name and Address

   Age      First
Became Officer
and/or Director
  

Position(s)

Donald W. Prosser

7260 Osceola Street

Westminster, CO 80030

   63      September 2003    Chairman and Chief Financial Officer

Nicholas Scheidt

7260 Osceola Street

Westminster, CO 80030

   53      November 2012    Director and Chief Executive Officer

Charles B. Davis

7260 Osceola Street

Westminster, CO 80030

   56      October 2007    Director and Chief Operating Officer

Charles L. Gamber

7260 Osceola Street

Westminster, CO 80030

   64      September 2003    Director and Secretary

William W. Stewart

7260 Osceola Street

Westminster, CO 80030

   53      December 2001    Director and Assistant Secretary

Donald W. Prosser

Mr. Prosser is a Director and member of our Compensation and Audit Committees. Mr. Prosser is a practicing certified public accountant, specializing in tax and securities accounting, and has represented a number of companies serving in the capacity of CPA, member of boards of directors, and as Chief Financial Officer. Mr. Prosser brings to the Company an experienced depth of expertise in tax and securities compliance and accounting, corporate finance transactions and turn-around.

From 1997 to 1999, Mr. Prosser served as CFO and Director for Chartwell International, Inc, a publicly traded company which filed reports under the Exchange Act which published high school athletic information and provided athletic recruiting services. From 1999 to 2000, he served as CFO and Director for Anything Internet, Inc. and from 2000 to 2001, served as CFO and Director for its successor, Inform Worldwide Holdings, Inc., which is a publicly traded company which filed reports under the Exchange Act. From 2001 to 2002, Mr. Prosser served as CFO and Director for Net Commerce, Inc, a public company selling internet services. From November 2002 through June 2008, Mr. Prosser served as CFO of VCG Holding Corp., a publicly traded company which filed reports under the Exchange Act and engaged in the business of acquiring, owning and operating nightclubs. His accounting firm performs accounting service for VCG Holding Corp. From July 2008 through August 2009 Mr. Prosser was chief financial officer of IPtimize, Inc., a provider of broadband and data services that filed a petition under federal bankruptcy laws in October 2009. Since July 2013 he has served as a director of MusclePhar Corporation, a publicly traded company that has a class of securities registered under the Exchange Act.

Mr. Prosser has been a certified public accountant since 1975, and is licensed in the state of Colorado. Mr. Prosser attended the University of Colorado from 1970 to 1971 and Western State College of Colorado from 1972 to 1975, where he earned a Bachelor’s degree in both accounting and history (1973) and a Masters degree in accounting – income taxation (1975).

Charles B. Davis

Mr. Davis joined Arête’s Board of Directors in 2006, and serves as a member of the Company’s Nominating and Compensation Committees. From January 1981 to June 1983, Mr. Davis was Operations Manager for Keba Oil and Gas Co. where he was responsible for drilling, completion and producing operations. From July 1983 to April 1986, Mr. Davis was Vice-President of operations for Private Oil Industries. From April 1986 until August 1988, Mr. Davis did consulting work related to well site operations. Since August 1988 Mr. Davis has worked for DNR Oil & Gas Inc., as president, overseeing the day to day operations for 150 to 200 wells, and involved in exploration activities. Mr. Davis graduated from the University of Wyoming with a Bachelor of Science Degree in Engineering.

 

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Charles L. Gamber

Mr. Gamber joined Arête’s Board of Directors in September 2003. He serves as an independent director, and is a member of our Nominating, Audit, and Compensation Committees. Mr. Gamber is the owner of Charles L. Gamber, Inc. dba Capital Resource Management LLC and works as a consultant creating business opportunities and relationships with strategic partners and business organizations. He is also the Director of Business Development for MedCenterNetwork. He has over 35 years of sales, customer service and marketing experience. Mr. Gamber started Charles L Gamber, Inc., in 2003. Mr. Gamber received a bachelor’s degree in Business Administration with minors in Accounting and Economics from Western State College of Colorado in 1973.

William W. Stewart

From December, 2001 until August, 2002, Mr. Stewart ran the operations and directed the business plan of Eagle Capital Funding Corp. (Eagle Capital) to pursue capital funding projects. In addition to serving as an outside director, he serves as a member of the Company’s Nominating and Compensation Committees. Mr. Stewart worked in the brokerage industry as an NASD licensed registered representative from 1986 to 1994. Mr. Stewart started his career with Boettcher and Company of Denver, Colorado and left the Principal Financial Group of Denver, Colorado in 1994 to open his own small-cap investment firm, S.W. Gordon Capital, Inc., where he has been its president since 1994 to the present. Mr. Stewart formerly served as CEO and is an owner of Larimer County Sports, LLC, a Colorado limited liability company, which owns the Colorado Eagles Hockey Club a minor league professional hockey franchise in northern Colorado. He has been President of Wenatche Sports Partners, LLC, owner of a minor league hockey team, since 2008. Mr. Stewart attended the University of Denver on a full athletic scholarship where he played hockey from 1979 to 1983 as right wing and served as assistant captain during his senior year. Mr. Stewart graduated with a BS, Business Administration from the University of Denver in 1983, with honors as a Student Athlete.

Nicholas L. Scheidt

Mr. Scheidt joined the Company’s Board of Directors in November of 2012, and became the Chief Executive Officer in May 2013, and as a member of the Company’s Audit, Nomination and Compensation Committees. Mr. Scheidt has served as President and Chairman of Apex Financial Services Corp (aka Apex Realty Investments Inc.) since 1983; he has served on the Board of Directors of Truck Wash Inc. since 1989; he has served on the Board of Directors of Out Reach Housing Corporation since 1992 and he has served as Chief Financial Officer of Truck Wash Inc. since 1995.

Board Committees

Our Board of Directors oversees the business affairs of the Company and monitors the performance of our management. The Board of Directors met five times during the year 2013.

Director Independence

Our common stock is listed on the OTC Markets under the QB tier, which does not have director independence requirements. For purposes of determining director independence, we have applied the definition set forth in NASDAQ Rule 4200(a)(15). The following directors are considered “independence” as defined under Rule 4200(a)(15): Charles L. Gamber and William W. Stewart.

Audit, Compensation and Nominating Committees

As noted above, our common stock is listed on the OTC Markets, which does not require companies to maintain audit, compensation or nominating committees consisting solely of independent directors. Nonetheless, we maintain an audit, compensation and nominating committee, although the membership on these committees does not solely consist of independent directors.

Audit Committee

The Audit Committee’s primary responsibilities are to monitor our financial reporting process and internal control system, to monitor the audit processes of our independent auditors, and internal financial management; and to provide an open avenue of communication among our independent auditors, financial and senior management and the Board. The Audit Committee reviews its charter annually and updates it as appropriate. The Committee met four times during the year 2013.

Audit Committee Financial Expert

The Board has determined that Mr. Prosser is an audit committee financial expert; however, he is not independent within the meaning of Regulation S-K.

Nominating Committee

The Nominating Committee was also established in 2003. It identifies candidates for future Board membership and proposes criteria for Board candidates and candidates to fill Board vacancies, as well as a slate of directors for election by the shareholders at each annual meeting. The Committee annually assesses and reports to the Board on the Board Committee performance and effectiveness; reviews and makes recommendations to the Board concerning the composition, size and structure of the Board and its committees; and annually reviews and reports to the Board on director compensation and benefits matters. The Nominating Committee met one time during the year 2013.

 

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Compensation Committee.

While the Company established a Compensation Committee in 2003, our full Board currently administers compensation matters. As we expand our operations and compensation policies, we intend to appoint members to the committee. Upon reinstatement of the Committee, it will administer our incentive plans, sets policies that govern executives’ annual compensation and long-term incentives, and reviews management performance, compensation, development and succession.

Compliance with Section 16(a) of the Exchange Act.

The Company files reports under Section l5 (d) of the Exchange Act; accordingly, directors, executive officers and 10% shareholders are not required to make filings under Section 16 of the Exchange Act.

Shareholder Communications.

We do not have a formal shareholder communications process. Shareholders are welcome to communicate with the Company by forwarding correspondence to Arête Industries, Inc., Board of Directors, 7260 Osceola Street, Westminster, Colorado 80030, Attention: Donald W. Prosser, CFO and Director.

CODE OF BUSINESS CONDUCT AND ETHICS

Our corporate philosophy is that good ethics and good business conduct go hand in hand. Our business standards provide a general framework of values and obligations that should be adhered to at all times. Corporate standards guide our professional conduct in regard to actions, words, sense of fairness, honesty and integrity. The Company is required to comply with laws in all jurisdictions, and our Code of Business Conduct and Ethics, which we refer to as the Code, supports and reflects our statutory compliance with such laws. The Code applies to our principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.

 

ITEM 11. EXECUTIVE COMPENSATION

EXECUTIVE COMPENSATION

We do not currently have any full time or part time employees. Our three executive officers, who are also directors, did not receive any salary or other compensatory benefits during 2012 or 2013 in their capacity as officers. During 2012 and 2013, we used independent contractors, consultants, attorneys and accountants as necessary, to complement services for operations and regulatory filings.

We paid cash to Donald W. Prosser, P.C. CPA, of $50,000 for 2012 and no cash for 2013 for accounting and regulatory filing services. Mr. Prosser is our Chief Financial Officer and Director. We also paid Charles Davis $30,000 in 2012 for providing us with management services relating to our oil and gas properties. We also issued common stock to Mssrs. Prosser and Davis with a fair value of $30,000 each for 2012. See also “Certain Relationships and Related Transactions” for further information regarding certain transactions with our officers.

Equity Awards

We do not maintain any equity award plans. Accordingly, there were no stock grants, options or other equity awards to our two executive officers in their capacity as officers.

Compensation of Directors.

The following table discloses the cash, equity awards and other compensation earned, paid or awarded, as the case may be, to each of our non-employee Directors during the fiscal year ended December 31, 2013.

 

Name

   Fees
Earned
Or Paid in

Cash ($)
     Stock
Awards
($) (1)
     Option
Awards
($)
     All Other
Compensation
($)
     Total ($)  

Charles Davis

     —          450         —          —          450   

Charles Gamber

     —          450         —          —          450   

Donald W. Prosser

     —          450         —          —          450   

William Stewart

     —          450         —          —          450   

Nicholas Scheidt

     —          450         —          —          450   

 

(1) Our Directors are entitled to 300 shares of the Company’s common stock for each meeting attended. The fee was payable at the end of each calendar quarter and was calculated based on the closing price of our common stock as reported by the OTC Market as of the last day of each quarter. Each of the Company’s five directors attended five meetings resulting in an obligation for the Company to issue an aggregate of 9,760 shares with an estimated fair value of $2,250.

 

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Cash Compensation Paid to Directors

We currently do not pay any cash fees to our Directors for services provided in their capacity as Directors.

Equity Based Compensation Paid to Directors

Since we currently do not have any formal equity incentive plans, the stock issued to directors is allocated from our authorized shares. The offer and sale of shares issued in connection with the Directors’ fees are not registered with the SEC and are therefore “restricted securities” as that term is defined in Rule 144 of the SEC, and as such are subject to holding period requirements and other restrictions set forth in Rule 144.

Other

All Directors are reimbursed for their reasonable expenses incurred in connection with attending meetings.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth certain information regarding the beneficial ownership of the Company’s common stock as of March 31, 2014 by (i) each person known by the Company to beneficially own more than five percent of the outstanding shares of common stock, (ii) each current director and named executive officer of the Company and (iii) all executive officers and directors as a group. Except as indicated, the persons named in the table have sole voting and investment power with respect to all shares beneficially owned.

 

Title of Class

  

Name and Address of Beneficial Owner

Directors and Executive Officers

   Amount and Nature of
Beneficial Ownership
     Percent
of
Class
 
Common Stock   

Charles Davis, Director/COO

7260 Osceola Street

Westminster, Colorado 80030,

   Direct      2,076,534         16.70
Common Stock   

Charles L. Gamber, Director/Secretary

7260 Osceola Street

Westminster, Colorado 80030,

   Direct      20,159         0.19
Common Stock   

Nicholas L. Scheidt, Director

7260 Osceola Street

Westminster, Colorado 80030,

   Direct      1,629,864         13.14
Common Stock   

Donald W. Prosser, Chairman, CFO

7260 Osceola Street

Westminster, Colorado 80030,

   Direct      883,796         7.12
Common Stock   

William W. Stewart, Director

7260 Osceola Street

Westminster, Colorado 80030,

   Direct      156,554         1.26
        

 

 

    

 

 

 
Common Stock    Directors and Officers as a Group (5 persons)    Total:      4,766,907         38.42
        

 

 

    

 

 

 

 

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Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our officers and directors have advanced funds to pay for necessary expenses and costs of the Company. The following are the advances from the officers and directors as of December 31, 2012 and 2013 are unsecured and due on demand:

 

     2012      2013  

Advances – Donald W. Prosser , CEO & Director 9.7% Interest

   $ 20,000       $ 20,000   

Advances – Donald W. Prosser 8% Interest

     2,882         4,984   

Note payable– Fairfield Management Group (Donald W. Prosser) 7.50% Interest

     150,000         150,000   

Advances – William W. Stewart 8% Interest

     10,000         10,000   

Advances – William W. Stewart 9.7% Interest

     25,000         25,000   

Note Payable – Apex Financial Services (Nicholas L Scheidt) 7.5% Interest

     261,109         714,488   

Advances – Charles B. Davis 9.7% Interest

     40,000         40,000   
  

 

 

    

 

 

 

Balances

   $ 508,991       $ 964,472   
  

 

 

    

 

 

 

We had related party payables of accrued interest to the officers and directors above of $52,008 at December 31, 2013.

In May 2011 we entered into a purchase and sale agreement, amended in July, 2011, for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana with the Tucker Family Investments, LLLP, DNR and Tindall Operating Company, collectively, the “Sellers,” for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana. In addition, the agreement included an operating agreement for the continued operations of the purchased properties by DNR. DNR is principally owned by Charles B. Davis, our Chief Operating Officer and one of our directors. The consideration for the purchase was determined by bargaining between management of the Company and Mr. Davis, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price for the acquisition was $11,000,000. Potential additional purchase price payments are due under the following circumstances:

 

    The Colorado and Kansas properties provide for additional consideration that is payable to Sellers if proved producing reserves are increased on these properties through drilling or recompletion activities over a period of ten years after the closing date. To the extent that oil reserves increase, the Sellers are entitled to additional consideration of $250,000 for each increase of 20,000 net barrels. Furthermore, to the extent that oil and gas prices increase, the Sellers are entitled to additional consideration as the targeted price thresholds are exceeded for periods of 61 days. The maximum increase in purchase price for the Kansas and Colorado properties is limited to a maximum of $5 million.

 

    The properties located in Wyoming and Montana provide a similar formula as used for Colorado and Kansas that could result in an obligation for additional purchase consideration to the extent that we perform future drilling or recompletion activities in formations that are not producing as of the closing date. Further, if we sell properties where reserves have been proved up through drilling or recompletion, the Sellers have retained an interest of 70% in the net sales proceeds (after we receive a recovery of 125% of the original purchase price allocation attributed to the properties.

Notwithstanding the foregoing, the maximum increase in purchase price is limited to a maximum of $25 million. Due to sales of some of the properties to unrelated third parties and additional purchase price payable due because the $90 and $100 oil price thresholds were exceeded for 61 consecutive days, the maximum future consideration was reduced to approximately $19.8 million as December 31, 2013.

 

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We also entered into a contract operator agreement with DNR to operate all of the properties purchased pursuant to the purchase and sale agreement, as amended. Under the agreement, DNR:

 

    operates, manages, and maintains the properties in accordance with past practices;

 

    employs such personnel as may be reasonably necessary to operate the properties;

 

    provides various accounting and governmental reporting functions;

 

    purchases supplies, materials, tools and equipment associated with ownership and operation of the properties;

 

    pays and performs all obligations of Arête which relate to the properties, including, without limitation, the payment of operating costs, vendor invoices and contractor invoices associated with ownership or operation of the properties; and

 

    provides marketing, gas control and other similar services necessary to sell the oil and gas produced from the properties.

Under the contract operator agreement, we reimburse DNR for all third party costs and expenses, including without limitation, operating costs, capital expenditures, production taxes and producing, drilling and construction overhead charges billed by third party operators, incurred or borne by DNR and associated with the properties. In addition to the foregoing reimbursements, we pay DNR $23,000 per month for the performance of its services under the contract operator agreement. The operator agreement expired on March 31, 2012 and renews on a month to month basis. Effective July 1, 2012, the monthly operator fee was reduced to $18,000 per month.

On September 29, 2011, as part of our convertible preferred stock private placement of $5.225 million, Mr. Davis purchased 100 shares of our convertible preferred stock for $1 million. On September 29, 2011, as part of our convertible preferred stock private placement of $5.225 million, Mr. Scheidt purchased 100 shares of our convertible preferred stock for $1 million. Effective June 28, 2013, a number of holders of Arête Industries, Inc.’s (the “Company”) 15% Series A1 Convertible Preferred Stock (“Series A1 Preferred Stock”) elected to convert shares of such stock into the Company’s common stock at a deemed conversion price of $0.75 per common share. In connection with those conversions, the Company agreed to reduce the deemed conversion price from $3.35 per common share to $0.75 per common share and all such holders agreed to waive all dividend rights on their shares of Series A1 Preferred Stock subsequent to March 30, 2013. Mr. Davis and Mr. Scheidt elected to convert their preferred stock under these terms. Mr. Davis and Mr. Scheidt received 1,333,333 shares each this agreement.

On September 29, 2012, the Company borrowed $425,000 from an affiliate of a stockholder and director under a note agreement that provides for interest at the stated annual rate of 12% (and an effective annual rate of 17.8%) with unpaid principal and interest due on December 31, 2013. The outstanding principal balance as of December 31, 2012 was $261,109 principal and $5,064 interest due and was paid in full April 29, 2013.

On April 29, 2013, the Company executed a promissory note under which the Company agreed to pay Apex Financial Services Corp, a Colorado corporation, (“Apex”) the principal sum of $1,000,000, with interest accruing at an annual rate of 7.5%, with principal and interest due on May 31, 2014. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other assets sales to Apex to secure the debt. Apex is 100% owned by the CEO, director, and shareholder of the Company, Nicholas L. Scheidt. The Company borrowed the full amount of principal on the note, and also paid a loan fee of $10,000. In the event of default on the note and failure to cure the default in ten days, Apex may accelerate payment and the annual interest rate on the note will accrue at 18%. Default includes failure to pay the note when due or if the Company borrows any other monies or offers security in the Company or in the collateral securing the note prior to the note being paid in full. The outstanding principal balance as of December 31, 2013 was $714,488 and interest due in the amount of $5,565.

 

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On January 1, 2014, we memorialized our short-term liabilities into formal promissory notes. These certain outstanding advances and other notes payable are now included in single promissory notes, all have been reported previously in our financial statements. Information concerning these promissory notes is set forth in the table below.

 

Name of Holder

  

Position

   Principal
Amount
     Interest
Rate
    Monthly
P&I
Payment
Amount
     Number
of
Monthly
Payments

Donald W. Prosser

   CFO & Director    $ 28,500         7.00   $ 564.33       60

Charles B. Davis

   COO & Director    $ 66,500         7.00   $ 1,316.78       60

William Stewart

   Director    $ 49,500         7.00   $ 980.16       36

The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 18% per annum.

In addition, we also issued an unsecured promissory note in the amount of $792,151 on January 1, 2014 to DNR Oil & Gas, Inc. (“DNR”) to restructure its existing debt. DNR is a company controlled by one of our directors, Charles B. Davis. The DNR note accrues interest at the rate of 2.50% for the calendar years 2014 and 2015, 4.00% for the calendar year 2016, 6.00% for the calendar year 2017 and 8.00% for the remainder of the term of the DNR note. The DNR note matures on January 1, 2019. The DNR note requires payments as follows:

 

    One payment of $250,000 in 2016;

 

    One payment of $250,000 in 2017;

 

    One payment of $250,000 in 2018; and

 

    The balance of principal and accrued interest on or before January 1, 2019.

The DNR note contains customary default and acceleration provisions and provides for a default interest rate of 18% per annum. The DNR note is subordinate to the bank line of credit.

On January 28, 2014, we entered into a line of credit loan agreement for $1,500,000 due January 15, 2015 at a unrelated bank. The terms of the note are as follows: 1) the accrued interest is payable monthly starting February 28, 2014, 2) the interest rate is variable based on an index calculated based on a prime rate as published by the Wall Street Journal index (currently 3.25%) plus an add on index with the current and minimum rate of 6.5%, 3), the note has draw provisions, with the first draw of $479,701, 4) the note is secured by seven wells and leases owned by the Company, a certificate of deposit for $500,000 at CityWide Bank pledged by a third party, and 5) the personal guarantee of the Nicholas Scheidt, Chief Executive Officer.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following relate to aggregate fees billed for the last two fiscal years by the Company’s principal accountants concerning the Company’s: (1) audit; (2) for assurance and services reasonably related to the audit; (3) for tax compliance, advice, and planning; and (4) for other fees provided by the principal accountant for the following:

1. Audit Fees. $43,100 (2012) and $44,850 (2013)

2. Audit-Related Fees. $30,500 (2012) and $1,318 (2013)

3. Tax Fees. $-0- (2012 and 2013)

4. All Other Fees. $-0- (2012 and 2013)

5.(i) The Company’s Audit Committee’s pre-approval policies and procedures (described in paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X), are:

 

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Audit Committee Pre-Approval Policies and Procedures

As set forth in its charter, our Audit Committee has the sole authority to pre-approve all audit and non-audit services provided by our independent auditor. All services performed by Causey Demgen and Moore P.C. in 2012 and 2013 were pre-approved by our Audit Committee. Having considered whether the provision of the auditors’ services other than for the annual audit and quarterly reviews is compatible with its independence, the Audit Committee has concluded that it is.

The Audit Committee on an annual basis reviews audit and non-audit services performed by the independent auditors. All audit and non-audit services are pre-approved by the Audit Committee, which considers, among other things, the possible effect of the performance of such services on the auditors’ independence. All requests for services to be provided by the independent auditor, which must include a description of the services to be rendered and the amount of corresponding fees, are submitted to the Chief Executive or Financial Officer. The Chief Executive or Financial Officer authorizes services that have been pre-approved by the Audit Committee. If there is any question as to whether a proposed service fits within a pre-approved service, the Audit Committee chair is consulted for a determination. The Chief Executive or Financial Officer submits requests or applications to provide services that have not been pre-approved by the Audit Committee, which must include an affirmation by the Chief Executive or Financial Officer and the independent auditor that the request or application is consistent with the SEC’s rules on auditor independence, to the Audit Committee (or its chair or any of its other members pursuant to delegated authority) for approval.

(ii) 100 per cent of the fees billed by the principal accountant were approved by the Audit Committee (described in paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X).

6. The percentage (if over 50%) of hours expended on the principal accountant’s engagement to audit the Company’s financial statements for the most recent fiscal year done by persons other than the principal accountant’s full-time, permanent employees, was: Not applicable

 

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PART IV

Item 15. EXHIBITS

The following exhibits are filed with, or incorporated by reference in, this registration statement:

 

Exhibit
Number
  Description
  3.1   Restated Articles of Incorporation with Amendment adopted by shareholders on September 1, 1998 (filed as Exhibit 3.1 to Form 10-KSB for the year ended December 31, 1998 (filed with the SEC on April 16, 1999), and incorporated herein by reference).
  3.2   Articles of Amendment to the Articles of Incorporation of Arête Industries, Inc. – Preferences, Limitations and Relative Rights of 15% Series A1 convertible preferred stock (filed as Exhibit 3.1 to Form 8-K dated September 30, 2011, and incorporated herein by reference.)
  3.2(a)   Articles of Amendment to Articles of Incorporation dated May 29, 2012 – Preferences, Limitations and Relative Rights of 15% Series A1 Convertible Preferred Stock (filed as Exhibit 3.2(a) to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference.)
  3.3   Bylaws (filed as Exhibit 3.3 to Form 10-K for the year ended December 31, 2010 and filed with the SEC on March 30, 2011.)
10.1   Purchase and Sale Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated May 25, 2011 (filed as Exhibit 10.4 to Form 8-K dated May 25, 2011, and incorporated herein by reference.)
10.2   Security Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated May 25, 2011 (filed as part of Exhibit 10.4 to Form 8-K dated May 25, 2011, and incorporated herein by reference.)
10.3   Purchase agreement with PRB for purchase of pipeline (filed as Exhibit 10.1 to Form 8-K dated September 18, 2006, and incorporated herein by reference.)
10.4   Amended and Restated Purchase and Sale Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated July 29, 2011 (filed as Exhibit 10.5 to Amendment No. 1 to Form 8-K dated May 25, 2011 (filed with the SEC on August 5, 2011), and incorporated herein by reference.)
10.5   First Amendment to the Amended and Restated Purchase and Sale Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated August 12, 2011 (filed as Exhibit 10.8 to Amendment No. 1 to Form 8-K/A dated August 12, 2011 (filed with the SEC on August 18, 2011), and incorporated herein by reference.)
10.6   Second Amendment to the Amended and Restated Purchase and Sale Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated September 16, 2011 (filed as Exhibit 10.9 to Form 8-K dated September 16, 2011, and incorporated herein by reference.)
10.7   Promissory Note due to Pikerni, LLC ($250,000) (filed as Exhibit 10.7 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)
10.8   Promissory Note due to Fairfield Management Group, LLC ($150,000) (filed as Exhibit 10.8 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)
10.9   Amended and Restated Contract Operator Agreement between DNR Oil & Gas, Inc. and Arête Industries, Inc. (filed as Exhibit 10.9 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)
10.10   Agreement regarding Increase in Payments in respect of Amended and Restated Purchase and Sale Agreement (Exhibit C) (filed as Exhibit 10.10 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)
10.11   Promissory Note due to Apex Financial Services Corp. ($455,000) and Assignment of Proceeds (filed as Exhibit 10.11 to Amended Registration Statement on Form S-1 filed on October 26, 2012, and incorporated herein by reference)
10.12   Promissory Note due to Apex Financial Services Corp. dated April 2, 2013 (filed as Exhibit 10.12 to Form 8-K dated May 3, 2013, and incorporated herein by reference.)
10.13   Notice of Conversion by Burlingame Equity Investors II, LP, dated June 28, 2013 (filed as Exhibit 10.13 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)
10.14   Notice of Conversion by Burlingame Equity Investors Master Fund, LP, dated June 28, 2013 (filed as Exhibit 10.14 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)

 

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10.14    Notice of Conversion by Burlingame Equity Investors Master Fund, LP, dated June 28, 2013 (filed as Exhibit 10.14 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)
10.15    Promissory Note - Burlingame Equity Investors II, LP, dated June 28, 2013 (filed as Exhibit 10.15 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)
10.16    Promissory Note - Burlingame Equity Investors Master Fund, LP, dated June 28, 2013 (filed as Exhibit 10.16 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)
10.17    Form of Notice of Conversion for holders of Series A1 Preferred Stock other than Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP (filed as Exhibit 10.17 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)
10.18    Promissory Note, Dated January 28, 2014 City Wide Bank (filed as Exhibit 10.18 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)
10.19    Promissory Note, Dated January 28, 2014 Donald W Prosser (filed as Exhibit 10.19 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)
10.20    Promissory Note, Dated January 28, 2014 Charles B Davis (filed as Exhibit 10.20 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)
10.21    Promissory Note, Dated January 28, 2014 William Stewart (filed as Exhibit 10.21 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)
10.22    Promissory Note, Dated January 28, 2014 DNR Oil & Gas, Inc. (filed as Exhibit 10.22 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)
10.23    Extension of Burlingame Equity Investors II, LP Promissory Note, Dated January 28, 2014 (filed as Exhibit 10.23 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)
10.24    Extension of Burlingame Equity Investors Master Fund, LP Promissory Note, Dated January 28, 2014 (filed as Exhibit 10.24 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)
10.25    Direct stock purchase agreement between Arête Industries, Inc. and Burlingame Equity Investors Master Fund LP dated January 30, 2014 (filed as Exhibit 10.25 to Form 8-K dated February 21, 2014, and incorporated herein by reference.)
14    Code of Business Conduct and Ethics (filed as Exhibit 14 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)
21    List of Subsidiaries (filed as Exhibit 21 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)
23.1    Consent of Ryder Scott Company*
31.1    Certification of the Principal Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002. *
31.2    Certification of the Principal Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002. *
32.1    Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350. *
32.2    Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350. *
99.1    Reserve Estimate Report of Ryder Scott Company *
101   

The following materials are filed herewith:

(i) XBRL Instance, (ii) XBRL Taxonomy Extension Schema, (iii) XBRL Taxonomy Extension Calculation, (iv) XBRL Taxonomy Extension Definition, (v) XBRL Taxonomy Extension Labels, and (vi) XBRL Taxonomy Extension Presentation.

 

* Filed herewith.

 

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Table of Contents

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

  Arête Industries, Inc.
April 14, 2014   By:  

/s/ Nicholas L. Scheidt

    Nicholas L. Scheidt,
    Chief Executive Officer and Director

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

/s/ Charles L. Gamber

Charles L. Gamber

   Secretary and Director   April 14, 2014

/s/ Donald W. Prosser

Donald W. Prosser

   Chairman of the Board and Chief Financial Officer   April 14, 2014

/s/ Nicholas L. Scheidt

Nicholas L. Scheidt

   Director and Chief Executive Officer   April 14, 2014

/s/ William Stewart

William Stewart

   Director   April 14, 2014

 

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