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EX-99.1 - EX-99.1 - Carbon Natural Gas Coa11-6041_1ex99d1.htm
EX-99.3 - EX-99.3 - Carbon Natural Gas Coa11-6041_1ex99d3.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 8-K

 

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

 

Date of Report (Date of Earliest Event Reported): February 14, 2011 (February 14, 2011)

 

ST. LAWRENCE SEAWAY CORPORATION

(Exact name of registrant as specified in charter)

 

Delaware

 

000-02040

 

26-0818050

(State or Other Jurisdiction

of Incorporation)

 

(Commission File

Number)

 

(IRS Employer

Identification No.)

 

1700 Broadway, Suite 2020, Denver, Colorado

 

80290

(Address of principal executive offices)

 

(Zip code)

 

(720) 407-7030

(Registrant’s telephone number including area code)

 

200 Connecticut Avenue, Fifth Floor, Norwalk, Connecticut 06854

(Former Name or former address, if changed since last report)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

o            Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

o            Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

o            Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

o            Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 



 

Explanatory Note:                        The registrant is reporting several events in this Form 8-K:

 

·              Completion of acquisition or disposition of assets (merger).  Because the registrant previously was a shell company, this transaction is the registrant’s exit from shell company status.  Accordingly, pursuant to Item 2.01(f) of Form 8-K, this Report provides the disclosure required by the Securities and Exchange Commissions’ Form 10, for general registration of a class of securities under the Securities Exchange Act of 1934.

 

·              Additional Form 8-K events, which have occurred in connection with the merger, are reported within the Item 2.01(f) global disclosure.  Cross references are to the Item 2.01(f) captions of Form 10, as noted in the text.

 

8-K Item

 

Item Reference Within Item 2.01 of this Report

Item 3.02 — Unregistered Sales of Equity Securities

 

Item 10

Item 5.01 — Changes in Control of Registrant.

 

Items 4 and 5

Item 5.02 — Departure of Directors;

 

 

Election of Directors; Appointment of

 

 

Principal Officers

 

Items 5 and 6

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

 

The information disclosed in this Form 8-K  includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “1933 Act”) and Section 21E of the Securities Exchange Act of 1934 (the “1934 Act”).  All statements, other than statements of historical fact, are forward-looking statements.

 

Examples of such statements in this Report concern planned capital expenditures for oil and natural gas exploration in 2011; cash expected to be available for continued work programs; recovered volumes and values of oil and natural gas approximating estimates of oil and natural gas reserves; drilling and completion activities in the Appalachian and Illinois Basins; timing for drilling of additional wells; expected spacing for wells; compliance with all oil and gas exploration and environmental regulations; and all the other statements regarding future conditions and operations.

 

Additional forward-looking statements in this Report relate to estimates of production from wells owned by The Interstate Natural Gas Company, LLC; anticipated closing of the Asset Purchase Agreement with The Interstate Natural Gas Company, LLC; statements regarding representations about volumes and of hydrocarbons and production rates from The Interstate Natural Gas Company, LLC; and sources of capital to close the Asset Purchase Agreement with The Interstate Natural Gas Company, LLC.

 

These forward-looking statements are identified by their use of terms and phrases such as “may,” expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “anticipate,” “will,” “continue,” “potential,” and similar terms and phrases.  Though we believe that the expectations reflected in these statements are reasonable, they do involve certain assumptions, risks and uncertainties.

 

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Form 8-K Items

 

Section 2 - Financial Information

 

Item 2.01 Completion of Acquisition or Disposition of Assets

 

(a)                                  Date of Completion of the Transaction.

 

On February 14, 2011, St. Lawrence Seaway Corporation (“SLSC”), a Delaware corporation with offices in Norwalk, Connecticut, closed the January 31, 2011 Agreement and Plan of Merger (the “Merger Agreement”), between (i) the registrant SLSC and its subsidiary St. Lawrence Merger Sub, Inc. (“Merger Co.”), a Delaware corporation, and (ii) Nytis Exploration (USA) Inc., a Delaware corporation (“Nytis USA”).  As a result, Merger Co. has been merged with and into Nytis USA, and Nytis USA is a surviving subsidiary of SLSC.  This transaction is referred to as the “Merger.”  The Merger was an all stock-for-stock transaction (see subparagraph (d) below).

 

The Merger Agreement was filed as an exhibit to the Form 8-K filed on February 1, 2011.

 

(b)                                 Brief Description of the Assets Involved.

 

Nytis USA (executive office located in Denver, Colorado) and its subsidiary Nytis Exploration Company LLC, a Delaware limited liability company (“NEC,” with its office located in Catlettsburg, Kentucky), own interests in approximately 382 gross (170 net) producing natural gas wells on approximately 264,000 primarily undeveloped net acres in the Illinois (Illinois, Indiana and Kentucky), and Appalachian (Kentucky, Ohio, Tennessee and West Virginia) Basins.  Nytis USA holds approximately 98% of the membership interests of NEC.  Nytis USA has one additional subsidiary, Nytis Exploration of Pennsylvania LLC, a Pennsylvania limited liability company (“Nytis PA”), which in 2010 sold substantially all of its assets and is now in the process of winding up its business and dissolving.  Nytis USA holds 85% of the membership interests of Nytis PA.

 

The foregoing assets are the principal assets acquired in the Merger.

 

Nytis USA and NEC conduct exploration and development drilling activities on current acreage and are acquiring additional acreage in the Appalachian and Illinois Basins.

 

(c)                                  Identity of the Person(s) from whom the Assets were acquired or to whom they were sold and the Nature of any Material Relationship, other than in respect of the Transaction, between such Person(s) and the Registrant or any of its Affiliates, or any Director or Officer of the Registrant, or any Associate of any such Director or Officer.

 

The assets were acquired by the registrant SLSC’s subsidiary Merger Co. acquiring all the stock of Nytis USA (and thereby, all of Nytis USA’s equity interests in its subsidiaries NEC and Nytis PA).

 

Other than the relationships resulting from the Merger, there was and is no relationship (whether or not material) between (i) Nytis USA (or either of NEC or Nytis PA), or any of its officers, directors, or any of its shareholders or associates, and (ii) the registrant SLSC, or any of its officers, directors, or any of its shareholders or associates.

 

(d)                                 The Nature and Amount of Consideration given or received for the Assets and, if any Material Relationship is disclosed pursuant to Paragraph (c) of this Item 2.01, the Formula or Principle followed in determining the Amount of such Consideration.

 

The registrant SLSC issued 47,000,003 shares of Rule 144 restricted common stock to the former shareholders of Nytis USA, in exchange for all the issued and outstanding shares of Nytis USA

 

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common stock.  Upon closing, the SLSC shares issued in the Merger represent approximately 99% of its outstanding common stock (without taking into account previously outstanding warrants to purchase 250,000 shares).  The exchange ratio was 1,630.7553 SLSC shares for each 1 share of Nytis USA.

 

Additionally, all the outstanding options to purchase Nytis USA common stock have been converted to options to purchase common stock of the registrant SLSC, with the number of shares covered by the Nytis USA options, and the exercise prices thereof adjusted for the exchange ratio, so as not to constitute a modification, extension, or renewal of the options within the meaning of Section 409A of the Internal Revenue Code.

 

(e)                                  If the Transaction being reported is an Acquisition and if a Material Relationship exists between the Registrant or any of its Affiliates and the Source(s) of the Funds used in the Acquisition, the identity of the Source(s) of the Funds unless all or any part of the Consideration used is a Loan made in the Ordinary Course of Business by a Bank as defined by Section 3(a)(6) of the Act, in which case the Identity of such Bank may be omitted provided the Registrant: (1) has made a request for confidentiality pursuant to Section 13(d)(1)(B) of the Act; and (2) states in the Report that the Identity of the Bank has been so omitted and filed separately with the Commission.

 

No funds were used in the acquisition.

 

(f)                                    If the Registrant was a Shell Company, other than a Business Combination related Shell Company, as those Terms are defined in Rule 12b-2 under the Exchange Act (17 CFR 240.12b-2), immediately before the Transaction, the Information that would be required if the Registrant were filing a General Form for Registration of Securities on Form 10 under the Exchange Act reflecting all Classes of the Registrant’s Securities subject to the Reporting Requirements of Section 13 (15 U.S.C. 78m) or Section 15(d) (15 U.S.C. 78o(d)) of such Act upon Consummation of the Transaction.

 

Form 10 Disclosures

 

Explanatory Note:  Unless stated otherwise below, the words “Company” and “we” (and related first person plural nouns and adjectives) collectively refer to Nytis USA, its subsidiaries NEC and Nytis PA, and the registrant SLSC.

 

The following captions denominated “Item” correspond to the disclosure captions of Form 10.

 

Item 1: Business

 

Glossary of Natural Gas and Oil Terms

 

The terms defined in this section are used throughout this Report. The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a) of Regulation S-X. The entire definitions of those terms can be viewed on the SEC’s website at http://www.sec.gov.

 

Bbl

 

means one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or liquid hydrocarbons.

 

 

 

Bcf

 

means one billion cubic feet of natural gas.

 

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Bcfe

 

means one billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.

 

 

 

Bbtu

 

means one billion British Thermal Units.

 

 

 

Btu

 

means a British Thermal Unit, or the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit.

 

 

 

CBM

 

means coalbed methane.

 

 

 

Condensate

 

means liquid hydrocarbons associated with the production of a primarily natural gas reserve.

 

 

 

Developed acreage

 

means the number of acres which are allocated or held by producing wells or wells capable of production.

 

 

 

Development well

 

means 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; dry well

 

means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

 

 

 

Equivalent volumes

 

means equivalent volumes are computed with natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.

 

 

 

Exploitation

 

means ordinarily considered to be a form of development within a known reservoir.

 

 

 

Exploratory well

 

means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well or a service well.

 

 

 

Farmout

 

is an assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location or the undertaking of other work obligations.

 

 

 

Field

 

means an area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

 

 

Full cost pool

 

means the full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration, and development activities are included. Any costs related to production, general and administrative expense, or similar activities are not included.

 

 

 

Gross acres or gross wells

 

means the total acres or wells, as the case may be, in which a working interest is owned.

 

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Henry Hub

 

means the natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the NYMEX.

 

 

 

Lease operating expenses

 

means the expenses of lifting natural gas or oil from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

 

 

 

Liquids

 

describes oil, condensate, and natural gas liquids.

 

 

 

MBbls

 

means one thousand barrels of crude oil or other liquid hydrocarbons.

 

 

 

Mcf

 

means one thousand cubic feet of natural gas.

 

 

 

Mcfe

 

means one thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.

 

 

 

MMBtu

 

means one million British Thermal Units, a common energy measurement.

 

 

 

MMcf

 

means one million cubic feet of natural gas.

 

 

 

MMcfe

 

means one million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.

 

 

 

NGL

 

means natural gas liquids.

 

 

 

Net acres or net wells

 

is the sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.

 

 

 

NYMEX

 

means New York Mercantile Exchange.

 

 

 

Productive wells

 

means producing wells and wells that are capable of production, and wells that are shut-in.

 

 

 

Proved Developed Reserves

 

means estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

 

 

 

Proved Reserves

 

means quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices that are the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month

 

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price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

 

 

Proved Undeveloped Reserves

 

means estimated 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 recovery to occur.

 

 

 

PV-10

 

means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

 

 

 

Reservoir

 

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

 

 

 

Royalty

 

means an interest in an natural gas or oil lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

 

 

 

Standardized measure or present value of estimated future net revenues

 

means an estimate of the present value of the estimated future net revenues from proved natural gas or oil reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs, and operating expenses, but before deducting any estimates of U.S. federal income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using natural gas prices and operating costs at the estimation date and held constant for the life of the reserves.

 

 

 

Tcfe

 

means one trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.

 

 

 

Undeveloped Acreage

 

means acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

 

 

 

Working interest

 

means an operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property, and to receive a share of production.

 

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Corporate History

 

Nytis USA was organized as a Delaware corporation in 2004 to acquire, operate and sell natural gas and oil interests in the Appalachian and Illinois Basins of the United States.  Soon after formation, we  identified natural gas and oil interests located in Clearfield County, Pennsylvania, and formed (along with a minority owner) a subsidiary limited liability company, Nytis PA which acquired those interests.  Thereafter, we identified natural gas and oil interests (owned by Addington Exploration, LLC (“Addington”)) located primarily in Illinois, Indiana, Kentucky, Ohio, Tennessee and West Virginia.  We (along with a different minority owner) set up a subsidiary limited liability company, NEC, to acquire the Addington assets.

 

We continue to use NEC to acquire natural gas and oil interests complementary to the Addington assets, including the 2006 acquisition of Pennsylvania properties from DCPA, LLC (an affiliate of Delta Petroleum Corporation).

 

In the spring of 2010, Nytis PA and NEC sold all of their Pennsylvania assets and received aggregate proceeds of approximately $30.3 million ($21 million to NEC and $9.3 million to Nytis PA).  The assets sold comprised all of the assets of Nytis PA and as a result, this subsidiary is in the process of being dissolved and its business wound up.

 

Now, all of our natural gas and oil interests are owned by NEC, which continues to evaluate and acquire new properties.  As of the date this Report is filed, we own interests in approximately 382 gross (170 net) producing natural gas wells on about 264,000 primarily undeveloped net acres in the Appalachian and Illinois Basins.

 

Business Strategy and Strengths

 

Our strategy is to build value through consistent growth in reserves and production through drilling on existing properties, and acquiring more properties. We emphasize internally generated growth of land positions in low-risk, repeatable, unconventional resource plays, and invest significantly in technical staff, acreage and technology to build drilling inventory and establish value through drilling, and geological and engineering support.

 

Principal strategy components:

 

·                  Concentrate on unconventional resources in core operating areas.  Our current focus on the Appalachian and Illinois Basins allows us to capitalize on our regional expertise to optimize drilling and completion techniques and production, reserves and cash flow.  Numerous objective reservoirs permit us to allocate capital among opportunities based on risked well economics, with a view to balancing the portfolio and achieve consistent and profitable growth in production and reserves.

 

All of our proved reserves and resources are classified as unconventional, including fractured shale natural gas plays, tight gas sands, and coalbed methane.  Our technical team has significant experience in drilling vertical, horizontal and directional wells, as well as fracture stimulation of unconventional formations. We utilize the latest geologic, drilling and completion technologies to increase the predictability and repeatability of finding and recovering hydrocarbons in these unconventional plays.

 

Production increased from 1,000 Mcfe/d average for the year ended December 31, 2005, to 2,500 Mcfe/d for the year ended December 31, 2009, to 3,000 Mcfe/d at February 15, 2011.   Estimated proved reserves increased from 15.6 Bcfe at December 31, 2004 to 42.4 Bcfe at December 31, 2009.

 

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·                  Proven executive management team with track record of value creation.  We believe our management team’s experience and expertise in the Appalachian and Illinois Basins operating regions coupled with multiple resource play provides us with a distinct competitive advantage. Our management and technical personnel have extensive experience operating in the Appalachian and Illinois Basins and have successfully built and sold unconventional resource companies previously.  Please see “Item 5, Directors and Executive Officers and Significant Employees.”

 

·                  Low-risk development drilling in established resource plays, and flexibility in deployment of exploration and infrastructure capital.  We have a multi-year drilling inventory of approximately 3,000 potential drilling locations on existing acreage, and have drilled 92 wells from January 2005 through September 30, 2010 with an approximate 98% success rate.

 

Approximately 5% of the drilling locations are included in our estimated proved reserve base at December 31, 2009. The concentrated leasehold position has been delineated largely through drilling done by us, as well as with other industry players.

 

This property profile is always subject to change as we acquire and dispose of various parcels.  For examples, in 2010, in addition to selling all our interests (for approximately $30.3 million in gross proceeds) in Pennsylvania assets to a third party, we also sold some undeveloped acreage in West Virginia, bought an interest in 19 wells in Kentucky, and bought a 50% interest in a company that owns and operates a gas gathering system in the Illinois Basin (this latter transaction added to infrastructure for our coalbed methane play in the Illinois Basin).

 

In addition, in 2009, we were paid a total of $2.7 million for two separate farmout agreements, by which we reduced capital exposure to dry hole risk, and retain a significant working interest plus overriding royalty interest upside. See Note 4 to the audited consolidated financial statements, Note 5 to the unaudited consolidated financial statements included in this Report, and Management’s Discussion and Analysis of Financial Condition and Results of Operations, in Item 2, Financial Information.

 

·                  Low cost operation.  Our geographic and operating focus provides low finding and development and lease operating costs.

 

·                  Maintain financial flexibility and conservative financial position.  We typically use cash flow from operations and our bank credit facility to fund acquisition and development drilling. In 2010, we repaid $23.5 million of borrowings under our bank credit facility with proceeds from the 2010 disposition of the Pennsylvania assets. At September 30, 2010, we had $5.9 million of available borrowing capacity under the bank credit facility, which, together with operating cash flow, is expected to provide us with the financial flexibility to pursue our currently planned development drilling activities.

 

·                  Control over operating decisions and capital program.  At December 31, 2009, we had an average working interest of 72% in our producing wells and operated 75% of our production.  The high percentage of operated wells allows us to effectively control operating costs, timing of development activities, application of technological enhancements, marketing of production, and better manage our capital budget.  Additionally, our status as operator permits discretionary timing for much of our capital expenditures.  This allows a significant degree of flexibility to adjust size and timing of development in response to changing market conditions.

 

·                  Manage commodity price exposure through an active hedging program.  We maintain an active hedging program designed to mitigate volatility in commodity prices and regional basis

 

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                        differentials. As of September 30, 2010, we have entered into hedging contracts covering a total of approximately 280,000 MMBtu of our natural gas production from October, 2010 through April, 2014 at a weighted average price of $5.49 per MMBtu. For the nine months ended September 30, 2010, we hedged approximately 48% of our production at a weighted average price of $5.33 per MMBtu. Substantially all of the hedges are at regional sales points in our operating regions, which mitigates the risk of basis differential to the Henry Hub index.

 

·                  Manage midstream assets and secure firm takeaway capacity.  We own natural gas gathering and compression facilities in the Illinois Basin.  We believe access to gathering and processing infrastructure allows us to decrease dependence on third parties, better manage the timing of our development and the pricing to the markets to which we sell our production.  In addition, we believe that to the extent that we were at risk related to pipeline capacity constraints, we have secured sufficient long-term firm takeaway capacity on major pipelines to accommodate our existing and expected production.

 

Planned Expenditures for Oil and Gas Exploration and Development

 

We expect to spend the amounts set forth below for oil and gas expenditures for the year ending December 31, 2011.  Amounts shown do not reflect any expenditures for exploration and development activities on the properties which may be acquired from The Interstate Natural Gas Company, LLC, or the amount which may be paid therefor if such properties are acquired.

 

 

 

Expected Range

 

 

 

Area

 

of Expenditures

 

Application

 

 

 

 

 

 

 

Appalachian Basin

 

$3.0 - $3.6 million

 

5 to 6 (2.5 - 3.0 net) Horizontal Gas Shale Wells

 

 

 

$1.2 - $1.8 million

 

2 to 3 (2.0 - 3.0 net) Horizontal Oil Sandstone Wells

 

 

 

 

 

 

 

Illinois Basin

 

$1.4 - $1.8 million

 

3 to 4 (1.5 - 2.0 net) Horizontal CBM Wells

 

 

 

$80,000 - $105,000

 

6 to 8 (.5 - .7 net) Vertical CBM Wells

 

 

 

$600,000 - $700,000

 

Land and Pipeline Infrastructure

 

 

 

 

 

 

 

Total

 

$6.3 - $8.0 million

 

 

 

 

Financial information about segments

 

The Company operates in one industry segment.  We refer you to the Consolidated Financial Statements in this Report (Item 13).

 

Description of Business

 

Operational Areas

 

The certificate of incorporation of Nytis USA, limits its direct and indirect activities related to the exploration, development, production, marketing and sale of oil, gas, coalbed methane and other hydrocarbons to the United States (both onshore and offshore).  As a result, Nytis USA and its subsidiaries are precluded from oil and natural gas activities outside the United States.

 

Appalachian Basin

 

Through NEC, we own working interests in 186 gross wells (147 net) and royalty interests in an additional 150 wells located in Kentucky, Ohio and West Virginia, and have leasehold positions in

 

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approximately 10,000 net developed acres and approximately 159,000 net undeveloped acres.  As of September 30, 2010, average net sales were approximately 2,400 Mcf per day.   Objective formations are the Berea Sandstone, Chattanooga Shale, Devonian Shale, Lower Huron Shale and other natural gas objective zones.

 

The Illinois Basin

 

NEC owns working interests in 46 gross wells (23 net) coalbed methane wells located in the Illinois Basin. It has a leasehold position in approximately 3,000 net developed acres and approximately 92,000 net undeveloped acres.  We are presently engaged in geological and engineering evaluation of unconventional natural gas reservoirs in the basin and have established sustained natural gas production and sales from various formations at an average depth of 700 feet.  As of September 30, 2010, average net natural gas sales are approximately 700 Mcf per day (inclusive of approximately 300 Mcf per day related to an acquisition of properties consummated in December 2010).

 

Acquisition and Divestiture Activities

 

Acquisitions

 

We pursue acquisitions that meet our criteria for investment returns and are consistent with our low-risk development focus.  Acquisitions in and around our existing core areas enable us to leverage our cost control abilities, technical expertise, and existing land and infrastructure positions. In general, our acquisition program has focused on acquisitions of properties that have development drilling opportunities and undeveloped acreage. For detailed information on other acquisition transactions through September 30, 2010, please see Note 4 to the audited consolidated financial statements and Note 5 to the unaudited consolidated financial statements included in this Report.

 

Agreement to Purchase Assets of The Interstate Natural Gas Company, LLC

 

Terms of the Agreement

 

On February 14, 2011, The Interstate Natural Gas Company, LLC (a private limited liability company) and certain related parties, as seller (hereafter collectively referred to as “ING”), and NEC, as buyer, entered into an Asset Purchase Agreement (the “APA”) to purchase, for $29.6 million (subject to adjustment at closing) certain natural gas properties, natural gas gathering and compression facilities and other assets related thereto, all located in eastern Kentucky and four counties in West Virginia.  The following is a summary of the principal terms of the APA; reference is made to the complete text of the APA, which is filed as an exhibit to this Report.

 

ING has agreed to sell to us (i) some but not all of its leases and interests in oil and natural gas leases, and wells and wellbores thereon and related natural gas production equipment (ii) its partnership interests in various general partnerships wherein ING is the managing general partner (at closing, NEC will succeed ING as managing general partner of these general partnerships, and will own ING’s partnership interests therein); (iii) its partnership interests in other general partnerships in which it owns partnership interests, but is not the managing general partner; (iv) its interests in various farm-ins and similar agreements; (v) natural gas gathering and compression facilities; and (vi) various other contracts, vehicles and equipment of ING related to the assets to be purchased, and easements and rights-of-way relating to or used in connection with the ownership and operation of the assets to be acquired.

 

ING currently gathers its natural gas through a series of mostly 2-4 inch gathering lines to numerous meter stations.  At these meter stations the natural gas is delivered directly into interstate transmission lines or into other gatherers or into one of several systems owned by local production companies for

 

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redelivery into interstate transmission.  At closing, we will assume certain obligations to transport gas from wells owned by ING (or its affiliates) that NEC is not acquiring as well as obligations under other contracts and agreements that NEC is acquiring as part of this acquisition.

 

We are not buying all of ING’s assets, nor are we buying ING itself or its business generally.

 

We have 60 days following the date that the APA is executed to complete our due diligence review.  We paid $450,000 into an escrow account when the APA was signed.  Subject to closing, the effective date of the acquisition under the APA is January 1, 2011.  The purchase price is subject to adjustment:

 

(i)                                     up for all actual operating or capital expenditures or prepaid expenses attributable to the assets, (including if paid by ING at closing) paid by or on behalf of ING  in connection with the assets and attributable to the period between the effective date and closing.  These expenses will include royalties, rentals and other charges; ad valorem and other taxes based on or measured by ownership of the assets, third-party expenses under joint operating agreements, and similar items; and

 

(ii)                                  down for environmental and/or title defects related to the assets; money received by ING from the sale of production of natural gas and liquids after the effective date; costs and expenses relating to the assets attributable to the time before the effective date but not paid by ING; unpaid ad valorem and similar taxes which become due and payable or accrue prior to the effective date; the $450,000 escrow deposit; distributions by the general partnerships or other entities allocated to the interests we are buying, which are attributable to production or sale of oil or natural gas that occurred after the effective date; and similar items.

 

The APA may be terminated (a) by either party if the closing does not occur on or before April 30, 2011, other than for failure by the party seeking termination to comply with its obligations under the APA, including the obligation to close; (b) by either party if the total purchase price adjustments exceed $3 million; (c) by us if ING has violated or breached any of its material agreements, representations or warranties (including ING’s obligation to close in accordance with its obligation to close under the APA); and (d) by ING if we have violated or breached any of our material agreements, representations or warranties (including our obligation to close).

 

If termination is by reason of (b) or (c) in the preceding paragraph, or by us if ING doesn’t close, the entire $450,000 is required to be returned to us.  In addition, if we terminate by reason of (a) upon ING failing to close in accordance with the terms of the APA or by reason of (c), we may pursue legal and equitable remedies including specific performance or seek damages subject to a damage cap of $3 million unless ING’s failure to close is attributable to its negotiating with or closing a sale to a third party.  If termination is by reason of (d), or by ING under (a) after we fail to close in accordance with our obligation to close under the APA, the $450,000 will be retained by ING as liquidated damages.

 

Concerning the Assets to be Purchased; Financing the Purchase

 

Based on information provided by ING and its consultants and representatives, the assets to be acquired comprise working and royalty interests in some 449 producing wells, ING operates substantially all of the wells, and daily net production is estimated to be approximately 3,680 Mcf of gas and 10 barrels of liquids, or an equivalent daily production of 3,740 Mcfe.  Based on information provided to us by ING as well as an internal review of the reserves prepared by NEC’s staff of engineers with significant consultation with its geologists, the assets being purchased have approximately 30,700 MMcfe of proved developed producing reserves.  See “Preparation of Reserve Estimates” below in this Item 1 for a description of our method of determining reserves.  This information has been reviewed by us but has not been verified by independent analysis as of the date of this Report, however, we have engaged Cawley,

 

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Gillespie and Associates, independent petroleum engineers, to prepare a reserve report on the assets to be purchased, which we expect will be completed by mid-March 2011.  Additionally, as noted above, closing the APA is subject to satisfactory completion of our due diligence review of all matters addressed in the APA, including without limitation, title to assets and environmental matters.

 

None of the information in this Report concerning our properties, or otherwise, includes information about the assets which are the subject of the APA.

 

We negotiated the purchase price based upon our preliminary understanding of reserves and their value going forward, relative to current and anticipated natural gas prices.  While the independent reserve report could establish reserves which are higher or lower than our internal reserve estimates based on the information provided by ING, a “lower report” would not be grounds for terminating the APA and a “higher report” would not change the purchase price.

 

Financing the purchase price is anticipated to be obtained from our lending facility and by additional equity invested by our principal stockholders.  However, as of the date of this Report, we do not have commitments in place for such debt or additional equity.

 

Divestitures

 

In February and March of 2010, NEC and Nytis PA sold all of their assets located in Pennsylvania for a purchase price of $30.3 million ($21 million to NEC and $9.3 million to Nytis PA).  The assets sold comprised all of the assets of Nytis PA and as a result, this subsidiary is in the process of being dissolved and its business wound up.  In addition, the assets sold comprised all of the assets of NEC located in Pennsylvania, including approximately 160 wells with net monthly production of approximately 28.3 MMcf.   For detailed information on other divestiture transactions, please see Note 4 to the audited consolidated financial statements and Note 5 to the unaudited consolidated financial statements included in this Report.

 

Reserves

 

The following table summarizes our estimated quantities of proved reserves as of December 31, 2009, and December 31, 2008, and the pre-tax PV-10 (present value of future net revenues before income taxes discounted at 10%).  Pre-tax PV-10 value, which is not a financial measure accepted under General Accepted Accounting Principles (“GAAP”), is shown because it is a widely used industry standard.

 

Estimated Proved Reserves

Natural gas (MMcf)

 

 

 

At December 31,

 

 

 

2009

 

2008

 

Proved developed producing

 

20,076

 

24,170

 

Proved developed non-producing

 

1,798

 

2,867

 

Proved undeveloped

 

20,537

 

44,369

 

Total estimated proved reserves

 

42,411

 

71,406

 

Percent developed

 

51.6

%

37.9

%

PV- 10 (thousands)

 

$

26,421

 

$

56,417

 

Average pricing used (per Mcf)

 

$

4.36

 

$

6.27

 

 

As of December 31, 2009, Nytis had estimated proved reserves of 42.4 Bcfe. Of that total, 40.4 Bcfe (95%) were in the Appalachian Basin and 2.0 Bcfe (5%) were in the Illinois Basin.

 

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As of December 31, 2009, proved undeveloped reserves (“PUDs”) were estimated to be 20.5 Bcfe, or 48% of estimated proved reserves, compared to 44.4 Bcfe, or 62% of estimated proved reserves as of December 31, 2008. The net reduction of 23.9 Bcfe was primarily due to negative price-related revisions partially offset by extensions and discoveries. See Strategy—Acquisition and Divestiture Activities—Divestitures” above for a discussion of the divestitures completed during 2009.

 

Preparation of Reserves Estimates

 

Our reserve estimates as of December 31, 2009 presented herein were made in accordance with the SEC’s “Modernization of Oil and Gas Reporting” rules, which were effective for fiscal years ending on or after December 31, 2009. The new SEC rules include updated definitions of proved natural gas reserves, proved undeveloped natural gas reserves, natural gas producing activities and other terms used in estimating proved natural gas reserves. Proved natural gas reserves as of December 31, 2009 were calculated based on the prices for natural gas during the twelve month period before the reporting date, determined as unweighted arithmetic averages of the first-day-of-the-month prices for each month within such period, rather than the year-end spot prices, which had been used in years prior to 2009. Undrilled locations can be classified as having proved undeveloped reserves 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. The new SEC rules broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of natural gas producing activities to include the extraction of non-traditional resources, including natural gas extracted from shales as well as bitumen extracted from oil sands.

 

Our reserve estimates as of December 31, 2008 presented herein were made in accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities and applicable to fiscal years ending before December 31, 2009 and were determined using constant prices and unescalated costs based on prices received as of December 31, 2008.  See Notes 1 and 2 to the audited consolidated financial statements and Notes 2 and 3 to the unaudited consolidated financial statements included in this Report for additional information regarding our estimated proved reserves.

 

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of natural gas and oil that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development and production expenses, may require revision of such estimates. Accordingly, quantities of natural gas and oil ultimately recovered will vary from reserve estimates. SeeRisk Factors,” for a description of some of the risks and uncertainties associated with our business and reserves.

 

Reserve estimates included in this Report are prepared by NEC’s internal staff of engineers with significant consultation with internal geologists. The reserve estimates are based on production performance, data acquired remotely or in wells, and are guided by petrophysical, geologic, geophysical, and reservoir engineering models. Access to the database housing reserves information is restricted to select individuals from our engineering department. Moreover, new reserve estimates and significant changes to existing reserves are reviewed and approved by various levels of management, depending on their magnitude.

 

Richard Finucane is Chief Engineer for NEC.  In that capacity he oversees engineering, production, drilling and completion activities in Nytis’ operations, including property evaluation, acquisitions and divestitures.  Mr. Finucane has worked as an oil and natural gas engineer since 1978.  His initial

 

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experience was with Texaco Inc.  From 1982-1997 Mr. Finucane was employed by Ashland Exploration Company where his responsibilities included production optimization, facilities engineering, drill site selection, reservoir engineering and property evaluation.  Mr. Finucane holds a B.S. in Civil Engineering from the University of Tennessee (highest honors) and is admitted as an expert in oil and natural gas matters in civil and regulatory proceedings in Virginia, West Virginia, and Kentucky.

 

Item 1A.  Risk Factors

 

Natural gas and oil prices are volatile. A substantial or extended decline in natural gas and oil prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

 

Our financial condition, operating results, and future rate of growth depend upon the prices that we receive for our natural gas and oil. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our bank credit facility and through the capital markets. The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lender taking into account our estimated proved developed reserves and is subject to periodic redeterminations based on pricing models determined by the lender at such time. Declines in natural gas and oil prices have in the past adversely impacted the value of our estimated proved developed reserves and, in turn, the market values used by our lenders to determine our borrowing base. Future commodity price declines may have similar adverse effects on our reserves and borrowing base. SeeManagement’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Credit Facilities,” for more details. Further, because we have elected to use the full cost accounting method, each quarter we must perform a “ceiling test” that is impacted by declining prices. Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See “—Lower natural gas and oil prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.”

 

The markets for natural gas and oil have been volatile historically and are likely to remain volatile in the future. Oil spot prices reached historical highs in July 2008 and natural gas spot prices reached near historical highs in July 2008. Prices have declined significantly since that time and may continue to fluctuate widely in the future. The prices we receive for our natural gas and oil depend upon factors beyond our control, including among others:

 

·                                          worldwide and regional economic conditions impacting the global supply and demand for natural gas and oil;

 

·                                          the price and quantity of imports of foreign natural gas, including liquefied natural gas, and oil;

 

·                                          political conditions in or affecting other natural gas and oil-producing countries, including the current conflicts in the Middle East and conditions in Latin America, Russia and the independent states of the former Soviet Union;

 

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

 

·                                          the level of global natural gas and oil inventories;

 

·                                          prevailing prices on local natural gas and oil price indexes in the areas in which we operate;

 

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·                                          localized and global supply and demand fundamentals and transportation availability;

 

·                                          weather conditions;

 

·                                          technological advances affecting energy consumption;

 

·                                          the price and availability of alternative energy; and

 

·                                          domestic, local and foreign governmental regulation and taxes.

 

These factors make it very difficult to predict future commodity price movements with any certainty. We sell the majority of our natural gas and oil production at current prices rather than through fixed-price contracts. However, we do enter into derivative instruments to reduce our exposure to fluctuations in natural gas and oil prices. See “—Our future use of hedging arrangements could result in financial losses or reduce income” Nearly one hundred percent of our estimated proved reserves at December 31, 2009 were natural gas, and, as a result, our financial results will be more sensitive to fluctuations in natural gas prices.

 

Furthermore, the current worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has led to a worldwide economic recession. The slowdown in economic activity caused by such recession has reduced worldwide demand for energy and resulted in lower natural gas and oil prices. Natural gas spot prices have recently been particularly volatile and declined from record high levels in early July 2008 of over $13.00 per MMBtu to below $3.00 per MMBtu in September 2009 and below $4.00 per MMBtu for portions of 2010.

 

We have indebtedness and may incur more debt in the future. Our leverage may materially affect our operations and financial condition.

 

We (through NEC) have a bank credit facility with the Bank of Oklahoma, the outstanding balance of which as of September 30, 2010 was $2.1 million ($5.9 million available), and we may incur more debt in the future. This indebtedness may have several important effects on our business and operations; among other things, it may:

 

·                                          require us to use a significant portion of our cash flow to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general corporate purposes;

 

·                                          limit our access to the capital markets;

 

·                                          increase our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more restrictive covenants;

 

·                                          limit our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;

 

·                                          place us at a disadvantage compared to similar companies in our industry that have less debt; and

 

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·                                          make us more vulnerable to economic downturns and adverse developments in our business.

 

Our bank credit facility contains various restrictive covenants. A failure on our part to comply with the financial and other restrictive covenants contained in our bank credit facility could result in a default under these agreements. Any default under our bank credit facility could adversely affect our business and our financial condition and results of operations, and would impact our ability to obtain financing in the future. In addition, the borrowing base included in our bank credit facility is subject to periodic redetermination by our lender. A lowering of our borrowing base could require us to repay indebtedness in excess of the redetermined (lower) borrowing base. SeeManagement’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Credit Facility.

 

A higher level of debt will increase the risk that we may default on our financial obligations. Our ability to meet our debt obligations and other expenses will depend on our future performance. Our future performance will be primarily affected by natural gas prices (and to a lesser extent, oil prices), financial, business, domestic and global economic conditions, governmental regulations and environmental regulations, and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all.

 

A portion of our borrowings from time to time may be at variable interest rates, making us vulnerable to increases in interest rates.

 

Our estimates of proved reserves at December 31, 2009 have been prepared under new SEC rules that went into effect for fiscal years ending on or after December 31, 2009. The new SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

 

This Report includes estimates of our proved reserves as of December 31, 2009, which have been prepared and presented under the SEC’s new rules relating to the reporting of natural gas and oil exploration activities. These new rules are effective for fiscal years ending on or after December 31, 2009, and require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule has limited and may continue to limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down any proved undeveloped reserves that are not developed within the required five-year timeframe.

 

The SEC has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules. Accordingly, while the estimates of our proved reserves at December 31, 2009 included in this Report have been prepared based on what we believe to be reasonable interpretations of the new SEC rules, those estimates could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance as it becomes available.

 

The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this Report are not intended to represent their fair, or current, market value.

 

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

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The estimates of our reserves and the future net cash flows attributable to those reserves, were prepared internally by us.  The process of estimating natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. SeeDescription of Business—Reserves—Estimated Proved Reserves” for information about our estimated natural gas reserves and the PV-10 and standardized measure of discounted future net cash flows.

 

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

 

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing commodity prices and other factors, many of which are beyond our control.

 

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our proved reserves under the revised SEC regulations. Actual future prices and costs may differ materially from those used in the present value estimate.

 

The estimates of our reserves were prepared internally by us and have not been audited by an independent engineer. An independent audit of our reserves might cause us to adjust our estimates of reserves which could materially affect the quantities and present value of our reserves.

 

An independent engineer might interpret the available geological, geophysical, production and engineering data concerning our natural gas reserves differently than we have and might make different economic assumptions about natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  If such independent audit were undertaken, it might have resulted in materially different estimates of the estimated quantities and present value of our reserves which would have materially affected the amounts of depreciation, depletion and amortization expense available to and the net income of the Company.

 

52% of our total proved reserves as of December 31, 2009 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

 

As of December 31, 2009, 48% of our total proved reserves were undeveloped and 4% were developed non-producing. Although we plan to develop and produce all the proved reserves,  ultimately some may not be developed or produced.  In addition, not all of the undeveloped or developed non-producing reserves may begin producing at the expected times or within budget.

 

Lower natural gas and oil prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.

 

We use the full cost method of accounting to report our natural gas and oil operations. Under this method, we capitalize the cost to acquire, explore for, and develop natural gas and oil properties. Under full cost accounting rules, the net capitalized costs of proved natural gas and oil properties may not exceed a “ceiling limit,” which is based upon the present value of estimated future net cash flows from proved

 

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reserves, discounted at 10%. If net capitalized costs of proved natural gas and oil properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write-down.” Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write-down would not impact cash flow from operating activities, but it would reduce our shareholders’ equity. SeeManagement’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies, Estimates, Judgments, and Assumptions—Full Cost Method of Accounting,” below for further details.

 

Investments in unproved properties, including capitalized interest costs, are also assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized in the appropriate full cost pool. If an impairment of unproved properties results in a reclassification to proved natural gas reserves, the amount by which the ceiling limit exceeds the capitalized costs of proved natural gas reserves would be reduced.

 

We also assess the carrying amount of goodwill in the fourth quarter of each year and at other periods when events occur that may indicate an impairment exists. These events include, for example, a significant decline in natural gas prices.

 

The risk that we will be required to write-down the carrying value of our natural gas and oil properties, our unproved properties, or goodwill increases when natural gas and oil prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. For example, we recorded a non-cash ceiling test write-down of approximately $16.1 million in 2009. This write-down was reflected as a charge to net earnings. Additional write-downs of our full cost pool may be required if natural gas prices decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities in our full cost pool exceed the discounted future net cash flows from the additional reserves, if any, attributable to our cost pool.

 

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

 

The natural gas and oil industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development, exploitation, production and acquisition of natural gas and oil reserves. Cash flow used in investing activities related to capital and exploration expenditures was approximately $3.8 million in 2009 and $3.9 million for the nine months ended September 30, 2010.

 

The Company anticipates its budget for exploration and completion work on its existing acreage will range between $6 million and $8 million for 2011.  As we recognized an operating loss of $176,413 for the nine months ended September 30, 2010 (approximately $878,000 excluding $702,000 of hedging gains in the nine month period), our planned exploration and development drilling and completion activities may be limited or delayed if cash flow from producing activities or funds available from our credit facility are not sufficient to fund the anticipated level of capital expenditures.

 

We intend to finance future capital expenditures, to the extent that is prudent, through cash flow from operations, and significantly from borrowings under our bank credit facility.  However, our financing needs may exceed those resources, and thus require a substantial  increase in capitalization  through the issuance of debt or equity securities or sale or joint venturing of selected assets. The issuance of additional indebtedness may require that a portion of operating cash flow be used to service the debt,

 

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thereby reducing the amount of cash flow available for other purposes. The actual amount and timing of future capital expenditures may differ materially from estimates as a result of, among other things, availability of personnel, commodity prices, actual drilling results, the availability of drilling rigs and other services, materials and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures. Conversely, a significant improvement in product prices could result in an increase in our capital expenditures.

 

Our cash flow from operations and access to capital are  subject to a number of variables, primarily proved reserves, production volumes and prices, and the ability of our bank to lend.

 

Adverse events or trends related to these factors could reduce our ability to achieve or obtain the cash flow from operations, debt and/or equity capital necessary to sustain operations at current levels. Our Company, like the majority of smaller and mid-size independent oil and gas exploration companies, must continue acquiring and exploiting properties to replace depleting reserves, and the budget for these activities often will not be fully funded by operating cash flow.  Accordingly, the inability to access outside capital could result in a curtailment of operations relating to the development of our properties, which in turn could lead to a decline in reserves and adversely affect the business, and our financial condition and results of operations.

 

Distressed economic conditions also may adversely affect the collectability of trade receivables. For example, our accounts receivable are primarily from purchasers of our natural gas production and other exploration and production companies that own working interests in the properties that we operate.  This industry concentration could adversely impact our overall credit risk, because customers and working interest owners may be similarly affected by the same adverse changes.  In addition, the possibility of a renewed credit crisis and turmoil in financial markets could cause our commodity derivative instruments to be ineffective because a counterparty might be unable to perform its obligations or even seek bankruptcy protection.

 

Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due, any of which could have a material adverse effect on operations and financial results.

 

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.

 

We have approximately 3,000 potential drilling locations on our existing acreage. Our management team has specifically identified and scheduled certain drilling locations as an estimation of future multi-year drilling activities on existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, availability of qualified personnel, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering systems and pipeline transportation constraints, regulatory approvals and other factors. Accordingly, we cannot predict when or if the identified drilling locations will be drilled.

 

In addition, our leases on undeveloped acreage expire on various dates unless drilled and completed (thus “held by production” until the well(s) on the lease are plugged and abandoned) before the end of their primary terms.  As is customary in the petroleum exploration and production industry, Company

 

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management continually prioritizes the timing of all of drilling locations against drilling and completion costs, available capital, expected returns on capital (net of debt taken on for drilling and completion work), and lease expirations.  As one example of this process, management will have to take into account the fact that without drilling and completing undeveloped acreage in Illinois and Indiana by December 31, 2011, or renewal at expiration of their primary terms, leases on undeveloped acreage in those states (Indiana and Illinois, representing nearly 10% of our total undeveloped acreage) will expire in 2011.  See Description of Business — Acreage” and “-Undeveloped Acreage Expirations.”

 

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

 

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. As a result, we must locate, acquire and develop new reserves to replace those being depleted by production. We must do this even during periods of low prices when it is difficult to raise capital. Unless we conduct successful ongoing exploration, development and exploitation activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas and oil reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be adversely affected.

 

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

 

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our exploration, exploitation, development and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas or oil production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes. See “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling and completing wells is always uncertain before drilling and completion work is finished. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

 

·                                          delays imposed by or resulting from compliance with regulatory requirements;

 

·                                          pressure or irregularities in geological formations;

 

·                                          shortages of or delays in obtaining equipment, materials and qualified personnel;

 

·                                          equipment failures or accidents;

 

·                                          adverse weather;

 

·                                          declines in commodity prices;

 

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·                                          limited availability of financing at acceptable rates;

 

·                                          title problems; and

 

·                                          limitations in the market for natural gas and oil.

 

As part of our ongoing operations, we sometimes drill in new or emerging plays. As a result, our drilling in these areas is subject to greater risk and uncertainty.

 

We have a group that is responsible for identifying new or emerging plays. These activities are more uncertain as to ultimate profitability than drilling in areas that are developed and have established production, because of little or sometimes no past drilling results by third parties to guide lease acquisition and drilling work. We cannot assure you that our future drilling activities in emerging plays will be successful or, if successful, will achieve the potential resource levels that we currently anticipate based on the drilling activities that have been completed or will achieve the anticipated economic returns based on our current cost models.

 

Increasing costs could impact operating results.

 

Areas throughout the United States, including the Appalachian and Illinois Basins, are experiencing steadily rising costs for drilling and completion rigs, pipe, cement, electrical power, and other goods and services.  Over time, a failure of commodity prices to keep pace with the increased cost environment could adversely affect cash flow.

 

We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance.

 

Operations are subject to hazards and risks inherent in drilling, producing and transporting production, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other property damage.  We maintain insurance coverage against some, but not all, potential losses. Pollution and environmental risks generally are not fully insurable.  Existing insurance coverage may not be renewed.  The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

 

Our future use of hedging arrangements could result in financial losses or reduce income.

 

We may engage in hedging arrangements for a significant part of production to reduce exposure to price fluctuations in commodity prices.  These arrangements would expose Nytis to risk of financial loss in some circumstances, including when production is less than expected, the counterparty to the hedging contract defaults on its contract obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefits we would otherwise receive from increased commodity prices.

 

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and to make payments on our indebtedness, which could also limit our ability to borrow funds. Future collateral requirements will depend on arrangements with our counterparties, highly volatile natural gas prices and interest rates.

 

22



 

As of September 30, 2010, receivables from our derivatives counterparty was approximately $313,000. Any default by this counterparty on its obligations to us would have a material adverse effect on the Company’s financial condition and results of operations.

 

Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce.

 

The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months.  We may be provided with only minimal, if any, notice as to when these circumstances will arise, or their duration. In addition, future properties may be acquired which are not currently serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production.  As a result, we may not be able to sell production from these wells until the necessary systems are built.

 

We may incur losses as a result of title deficiencies.

 

We do not always retain attorneys to examine title before acquiring leases or mineral interests.  Prior to drilling a well, however, we (or the company that is the operator) obtain a preliminary title review to ensure there are no obvious title deficiencies.  As a result of such examinations, certain curative work must be done to correct deficiencies in title, and such curative work may be expensive.  In some instances, curative work may not be possible, and the interest is demonstrated to have been bought in error from someone who is not the owner.  In that event, our interest would be worthless.

 

We could lose our undeveloped mineral leases if we don’t drill and complete wells in a timely manner.

 

Leased mineral properties give the holder the right to drill and complete wells in a timely manner.  Leases have a contract term that is negotiated with the mineral owners.  Generally, if a well is drilled and completed, the lease term continues so long as there is production from the well.

 

Renewing leases on undrilled acreage may not be feasible due to increased cost or other reasons.  If we are unable to renew leases on undrilled acreage, we would have to write off the initial acquisition cost, which could be substantial.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

 

Our exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

 

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the

 

23



 

production and transportation of, natural gas and oil. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

 

Changes to existing or new regulations may unfavorably impact the Company, could result in increased operating costs, and could have a material adverse effect on our financial condition and results of operations.  For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in natural gas and oil exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available for such activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations, particularly at the local level, could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows.

 

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

 

We may incur significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment, health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. We are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. The public may comment on and otherwise engage in the permitting process, including through judicial intervention.  As a result, the permits we need may not be issued, or if issued, may not be issued in a timely manner or may impose requirements that restrict our ability to conduct operations.

 

In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Strict liability and joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken.

 

New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected.

 

The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and oil we produce.

 

Since early 2009, the U.S. Environmental Protection Agency (“EPA”) has been developing regulations to reduce emissions of “greenhouse gases” from new motor vehicles and other sources. On December 15, 2009, EPA officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such natural gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other

 

24



 

climatic changes. Although these findings by the EPA do not themselves impose any requirements, they allowed the agency to proceed with the adoption and implementation of regulations to restrict emissions of greenhouse gases as part of a coordinated national program under existing provisions of the federal Clean Air Act.

 

On May 7, 2010, as part of the first phase of the coordinated national program, the EPA officially published a set of regulations restricting greenhouse gas emissions and setting fuel economy standards for light-duty vehicles manufactured in model years 2012 through 2016. The EPA proposed additional greenhouse gas and fuel economy standards in October 2010, which would apply to heavy-duty vehicles for model years 2014 through 2018, as well as light-duty vehicles for model years 2017 through 2025. This year, the EPA also finalized regulations that require certain U.S. facilities to report greenhouse gas emissions.  Particularly, on November 30, 2010, the EPA officially published annual reporting requirements for petroleum and natural gas facilities including extraction, production, distribution, and transmission systems that emit 25,000 metric tons or more of carbon dioxide equivalent. Beginning on January 1, 2011, such facilities must collect and report the following data to the EPA: carbon dioxide and methane emissions from equipment leaks and venting; carbon dioxide, methane, and nitrous oxide emissions from flaring; onshore production stationary and portable combustion emissions; and combustion emissions from stationary equipment involved in natural gas distribution. Reports must be submitted annually with the first report due to the EPA by March 31, 2012, for emissions during 2011.

 

Facilities covered by this rule might also be required to report emissions under other parts of the EPA’s greenhouse gas reporting program. Facilities that conduct geologic sequestration of carbon dioxide and all other facilities that inject carbon dioxide underground are also required to report greenhouse gas data to the EPA annually. The adoption and implementation of these regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and could adversely affect demand for the natural gas that we produce.

 

Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would have established an economy wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would have required a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. This legislation called for the EPA to issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere, with allowances expected to escalate significantly in cost over time. The net effect of ACESA would have been to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. Once the House passed ACESA, the next step would have been for the U.S. Senate to pass its own legislation restricting domestic greenhouse gas emissions, and several legislative proposals were made and passed out of committee. Ultimately, however, capping greenhouse gas emissions lacked bipartisan support in the Senate, and action on climate legislation was effectively ended for the current Congress. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas that we produce.

 

Even though such legislation has not yet been adopted at the national level, nearly one-half of the states have begun taking actions to control and/or reduce emissions of greenhouse gases. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as coal-fired electric power plants, it is possible that smaller sources of emissions could become subject to

 

25



 

greenhouse gas emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

 

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

 

In June 2009, legislation was introduced in both the House and Senate to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Both bills are still in committee.

 

Separately, the EPA has commenced the process of studying the possible relationship between hydraulic fracturing and drinking water, the initial results of which the EPA expects in late 2012. To receive input on development of the draft study plan, the EPA held public meetings in four locations across the country in July and September 2010, which attracted hundreds of protestors. Also in September 2010, the EPA issued voluntary information requests to nine of the leading national and regional hydraulic fracturing service providers. Although eight of the nine hydraulic fracturing companies agreed to voluntarily compile and submit the information requested by the EPA, one company refused and the EPA issued a subpoena. Because of heightened public awareness and concern related to hydraulic fracturing, additional federal regulation by the EPA, Congress, or both is likely in the coming years. If adopted, such rules could lead to operational delays or increased operating costs and could result in additional regulatory burdens that would make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

 

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

 

On July 21, 2010, President Obama signed in to law the “Dodd-Frank Wall Street Reform and Consumer Protection Act,” or “Dodd-Frank Act,” a broad financial regulatory reform legislation that among other things imposes comprehensive regulation on the over-the-counter derivatives marketplace and affects the use of derivatives in hedging transactions. The law subjects swap dealers and “major swap participants” to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also requires central clearing for transactions entered into between swap dealers or major swap participants. For these purposes, a major swap participant generally is someone other than a dealer who maintains a “substantial” net position in outstanding swaps (excluding swaps used for commercial hedging or for reducing or mitigating commercial risk) or whose positions create substantial net counterparty exposure that could have serious adverse effects on the financial stability of the U.S. banking system or financial markets.

 

The law also authorizes the Commodity Futures Trading Commission (“CFTC”) to impose position limits for over-the-counter derivatives related to energy commodities, and the CFTC has indicated that it will write rules to regulate the swaps marketplace pursuant to that authority. Separately, in late January 2010, the CFTC proposed regulations that would impose speculative position limits for certain futures and option contracts in natural gas, crude oil, heating oil, and natural gasoline. These proposed regulations would have made an exemption available for certain bona fide hedging of commercial risks.

 

26



 

As a result of the broadened scope and new requirements of the Dodd-Frank Act and with plans to propose speculative position limits and exemptions therefrom for all regulated exempt commodity derivatives, including energy derivatives, as directed by the Dodd-Frank Act, the CFTC withdrew these proposed regulations in August 2010. On November 2, 2010, the CTFC officially published proposed regulations that require position reports on economically equivalent swaps from clearing organizations, their members and swap dealers. These regulations affect forty-six specific exempt and agricultural commodities, including natural gas, crude oil, heating oil, and natural gasoline. Public comment closed on December 2, 2010, after which the CFTC will begin the process of finalizing the proposed regulations.

 

Any laws or regulations that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

 

Competition in the natural gas and oil industry is intense, making it more difficult for us to acquire properties, market natural gas and oil and secure trained personnel.

 

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing our production and securing trained personnel. Also, there is substantial competition for capital available for investment in the natural gas and oil industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition and results of operations.

 

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and field services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

 

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Historically, there have been shortages of qualified personnel, drilling and workover rigs, pipe and other equipment and materials as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

 

The loss of senior management or technical personnel could adversely affect operations.

 

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Patrick McDonald, our Chairman, President and Chief Executive Officer, and Kevin Struzeski, our Chief Financial Officer, Treasurer and Secretary, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

 

27



 

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

 

A portion of our business activities is conducted through joint operating agreements under which we own partial interests in oil and gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

 

We may be subject to risks in connection with acquisitions of properties.

 

The successful acquisition of producing properties requires an assessment of several factors, including:

 

·                                          recoverable reserves;

 

·                                          future commodity prices and their applicable differentials;

 

·                                          operating costs; and

 

·                                          potential environmental and other liabilities.

 

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even with inspections. Additionally, when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

 

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

 

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

 

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business,

 

28



 

financial condition and results of operations.  See “DESCRIPTION OF BUSINESS - Acquisition and Divestiture Activities - Potential Acquisition of Additional Natural Gas Assets

 

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to natural gas and oil exploration and development are eliminated as a result of future legislation.

 

President Obama’s proposed budget for fiscal year 2011 contains a proposal to eliminate certain key U.S. federal income tax preferences currently available to natural gas and oil exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Similar proposals were made by the administration for the fiscal year 2010 to no avail. The Oil Industry Tax Break Repeal Act of 2009, which was introduced in the Senate on April 23, 2009, includes many of the same proposals but remains in committee.

 

It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal, the Senate bill or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to natural gas and oil exploration and development. Any such change could negatively impact our financial condition and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

 

Item 2.    Financial Information

 

Selected Financial Data

 

The following is derived from and should be read in conjunction with the consolidated financial statements included in this Report.

 

 

 

Nine Months

 

 

 

 

 

 

 

Ended

 

 

 

 

 

 

 

Sept. 30,

 

Year Ended December 31,

 

(in thousands)

 

2010

 

2009

 

2008

 

 

 

(unaudited)

 

 

 

 

 

Balance Sheet Data

 

 

 

 

 

 

 

Current assets

 

$

2,696

 

$

1,638

 

$

2,546

 

Current liabilities

 

1,372

 

2,030

 

1,849

 

Working capital (deficit)

 

1,324

 

(392

)

697

 

Total assets

 

25,999

 

48,572

 

62,456

 

Non-current liabilities

 

5,489

 

30,301

 

30,734

 

Shareholder’s Equity

 

19,138

 

16,241

 

29,874

 

 

29



 

 

 

Nine Months

 

 

 

 

 

 

 

Ended

 

 

 

 

 

 

 

Sept. 30,

 

Year Ended December 31,

 

(in thousands)

 

2010

 

2009

 

2008

 

 

 

 

 

 

 

 

 

Operating Data

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

Oil and gas

 

$

4,492

 

$

5,902

 

$

9,830

 

Interest and other income

 

10,171

 

373

 

471

 

Expenses

 

5,215

 

24,676

 

8,126

 

Provision for income taxes/

 

 

 

 

 

 

 

(deferred tax benefit)

 

5,404

 

(4,784

)

 

Net income (loss)

 

4,044

 

(13,617

)

2,175

 

Net income (loss) attributed to

 

 

 

 

 

 

 

non-controlling interests

 

(913

)

 

(55

)

Net income (loss) attributed to

 

 

 

 

 

 

 

controlling interests

 

3,131

 

(13,617

)

2,120

 

 

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

 

Nytis USA is an independent natural gas and oil company engaged in the acquisition, exploration, development and production of natural gas and oil properties located in the Appalachian and the Illinois Basin of the United States. We focus on unconventional reservoirs, including fractured shale gas plays, tight gas sands and coalbed methane.  Our corporate headquarters are in Denver, Colorado and Catlettsburg, Kentucky.

 

Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience developing natural gas and oil resource plays to profitably grow our reserves and production, primarily through internally generated projects on our existing acreage and acquisitions within our core geographic areas. As of December 31, 2009, substantially all of our proved reserves were natural gas, 52% were proved developed and 75% of our production was operated by us. From December 31, 2004 through December 31, 2009, we grew our estimated proved reserves from 15.6 Bcf to 42.4 Bcf. In addition, we grew our average daily production from 1,000 Mcf/d for the year ended December 31, 2005 to 2,500 Mcfe/d for the year ended December 31, 2009.

 

We have assembled a diversified portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and a large inventory of repeatable drilling opportunities. Our drilling opportunities are focused in the Appalachian and Illinois Basins. From January 2005 through September 30, 2010, we have drilled 92 wells with a success rate of approximately 98%. Our drilling inventory consists of approximately 3,000 potential locations, all of which are resource-style opportunities and approximately 5% of which are included in our estimated proved reserve base as of December 31, 2009. For information on the possible limitations on our ability to drill our potential locations, see “Risk Factors—Risks Relating to Our Business—Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.”

 

For the year ended December 31, 2009, we spent approximately $4.0 million on capital expenditures, approximately 77% of which is allocated to low-risk development projects with the remaining capital allocated to infrastructure projects and land acquisition. For the nine months ended September 30, 2010, we spent $3.9 million on capital expenditures, approximately 45% of which is allocated to low-risk

 

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development projects with the remaining capital allocated to infrastructure projects. land acquisition and the acquisition of oil and gas properties.  This lower level of capital expenditures was intended to maintain financial flexibility and sufficient liquidity to sustain our assets and operations until the margins on natural gas improved.  Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget based on liquidity, commodity prices and drilling results.

 

We believe we have a conservative financial position characterized by modest leverage and hedging and ample liquidity. We have entered into hedging contracts covering a total of approximately 280,000 MMBtu of our natural gas production from October 1, 2010 through April 1, 2012 at a weighted average index price of $5.49 per MMBtu.

 

We operate in one industry segment, which is the acquisition, exploration, development and production of natural gas and oil and all of our operations are conducted in the United States.

 

Revenue Sources

 

Our production revenues are entirely from the continental United States and for the nine months ended September 30, 2010 are comprised of 99% natural gas and 1% oil and liquids. Gas prices reached historically high levels in recent years and reached over $13.00 per MMBtu in July 2008. Since then, natural gas prices have declined sharply to below $3.00 per MMBtu in September of 2009 and below $4.00 per MMBtu in September 2010. Natural gas and oil prices are inherently volatile and are influenced by many factors outside of our control. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a portion of our production. We currently use fixed price swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold. At each period end we estimate the fair value of these swaps and recognize any unrealized gain or loss. We have not elected hedge accounting and, accordingly, the unrealized gains and losses on open positions are reflected currently in earnings. We expect continued volatility in the fair value of these swaps.

 

Principal Components of Our Cost Structure

 

·                  Lease operating and gathering, compression and transportation expenses.  These are daily costs incurred to bring natural gas and oil out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our natural gas properties.

 

·                  Production taxes.  Production taxes consist of severance and ad valorem taxes and are paid on natural gas and oil produced based on a percentage of market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities.

 

·                  Depreciation, depletion, amortization and impairment.  The Company uses the full cost method of accounting for oil and gas properties.  All costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment are capitalized.  The Company historically has performed a ceiling test quarterly.  The full cost ceiling test is a limitation on capitalized cost prescribed by the SEC.  The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation that compares the net capitalized costs of the Company’s full cost pool to estimated discounted cash flows.  Should the net capitalized cost exceed the sum of the estimated discounted cash flows, a ceiling test write-down would be recognized to the extent of the excess.

 

31



 

The December 31, 2009 ceiling test was based on average first-of-the-month prices during the twelve-month period prior to December 31, 2009 pursuant to the SEC’s new “Modernization of Oil and Gas Reporting” rule.  The Company’s oil and gas properties exceeded the ceiling limitation by $16.1 million and accordingly, the Company recorded the excess as a non-cash charge to income for the year ended December 31, 2009.  Based on the prior rules utilizing spot prices at the end of the year, the Company would not have exceeded its ceiling limitation.  The December 31, 2008 ceiling test, based on spot prices at December 31, 2008, did not result in a write down.

 

Depletion is calculated using the capitalized costs in the full cost pool, including estimated asset retirement costs and the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values and depleted based on a unit-of-production method.

 

·                  General and administrative expense.  These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit, tax, legal and other professional fees and legal compliance.

 

·                  Interest expense.  We finance a portion of our working capital requirements and acquisitions with borrowings under our bank credit facilities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We will likely continue to incur interest expense as we continue to grow.

 

·                  Income tax expense.  Each of Nytis USA’s subsidiaries file separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities. We are subject to state and federal income taxes but historically have not been in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). However, in 2010, due to the sale of our Pennsylvania assets we are subject to federal and state income taxes.  We do pay some state income or franchise taxes where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis. Collectively, our operating entities have generated net operating loss carryforwards which expire starting in 2025 through 2029. For the year ended December 31, 2009, we recognized the full value of these net operating losses on our balance sheets because our management team believes it is more likely than not that we will realize a future benefit equal to the full amount of the loss carryforward in 2010, subject to Alternative Minimum Tax limitation due to the disposition of the Company’s Pennsylvania assets in 2010. The amount of deferred tax assets considered realizable, however, could change in the near term as we generate taxable income or estimates of future taxable income are reduced.

 

Significant Acquisitions and Dispositions

 

In the second half of 2009, we initiated a divesture program targeted at selling certain non-core gas properties with the primary intent to use the proceeds from the divestures to reduce outstanding debt.  During 2010, we completed our divestiture program with the sale of our Pennsylvania assets and used the proceeds to significantly reduce the outstanding amounts under our bank credit facilities.  The following table presents a summary of our significant acquisitions and dispositions for the years ended December 31, 2010 and 2009. There were no significant acquisitions or dispositions in 2008.

 

32



 

Primary locations of 
acquired properties

 

Date acquired

 

Purchase price

 

 

 

 

 

(in millions)

 

 

 

 

 

 

 

Illinois Basin (IL/IN)

 

December 2010

 

$

0.5

 

Illinois Basin (IL)

 

September 2010

 

$

0.6

 

Appalachian Basin (KY)

 

June 2010

 

$

1.3

 

 

Primary locations of 
dispositions 

 

Date disposed

 

Sales price

 

 

 

 

 

(in millions)

 

 

 

 

 

 

 

Appalachian Basin (WV)

 

September 2010

 

$

0.7

 

Appalachian Basin (PA)

 

March-April 2010

 

$

30.3

 

Appalachian Basin (WV)

 

July 2009

 

$

2.5

 

 

Our acquisitions were financed with a combination of borrowings under our credit facilities and cash flow from operations.

 

33



 

Results of Operations

 

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.

 

The following discussion and analysis relates to items that have affected our results of operations for the nine months ended September 30, 2010 and 2009.  The following table sets forth, for the periods presented, selected historical statements of operations data.  The information contained in the table below should be read in conjunction with the unaudited consolidated financial statements contained in this Report.

 

 

 

Nine Months Ended

 

 

 

 

 

 

 

September 30,

 

Increase /

 

Percent

 

(in thousands)

 

2010

 

2009

 

(Decrease)

 

Change

 

Revenue:

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

 

$

4,492

 

$

4,227

 

$

265

 

6.3

%

Other income

 

256

 

229

 

27

 

11.8

%

Total revenues

 

$

4,748

 

$

4,456

 

$

292

 

6.6

%

 

 

 

 

 

 

 

 

 

 

Expenses:

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

767

 

$

801

 

$

(34

)

-4.2

%

Transportation costs

 

226

 

268

 

(42

)

-15.7

%

Production and property taxes

 

312

 

475

 

(163

)

-34.3

%

General and administrative

 

2,412

 

1,779

 

633

 

35.6

%

Depreciation, depletion and amortization

 

1,194

 

1,889

 

(695

)

-36.8

%

Accretion of asset retirement obligations

 

13

 

32

 

(19

)

-59.4

%

Other expense

 

 

1

 

(1

)

-100.0

%

Total expenses

 

$

4,924

 

$

5,245

 

$

(321

)

-6.1

%

 

 

 

 

 

 

 

 

 

 

Other income and expenses:

 

 

 

 

 

 

 

 

 

Interest income

 

29

 

28

 

1

 

3.6

%

Interest expense

 

(291

)

(883

)

592

 

-67.0

%

Gain on sale of properties

 

9,886

 

 

9,886

 

*

 

Total other income and expenses

 

$

9,624

 

$

(855

)

$

10,479

 

 

 

 

 

 

 

 

 

 

 

 

 

Production data:

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

750

 

1,015

 

(265

)

-26.1

%

Oil and liquids (Bbl)

 

990

 

601

 

389

 

64.7

%

Combined (MMcfe)

 

756

 

1,019

 

(263

)

-25.8

%

 

 

 

 

 

 

 

 

 

 

Average prices before effects of hedges:

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

4.98

 

$

4.06

 

$

0.92

 

22.7

%

Oil and liquids (per Bbl)

 

$

57.15

 

$

36.23

 

$

20.92

 

57.7

%

Combined (per Mcfe)

 

$

5.02

 

$

4.07

 

$

0.95

 

23.3

%

 

 

 

 

 

 

 

 

 

 

Average prices after effects of hedges:

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

5.92

 

$

4.14

 

$

1.78

 

43.0

%

Oil and liquids (per Bbl)

 

$

57.15

 

$

36.23

 

$

20.92

 

57.7

%

Combined (per Mcfe)

 

$

5.94

 

$

4.07

 

$

1.87

 

45.9

%

 

 

 

 

 

 

 

 

 

 

Average costs (per Mcfe):

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

1.02

 

$

0.79

 

$

0.23

 

29.1

%

Transportation costs

 

$

0.30

 

$

0.26

 

$

0.04

 

15.4

%

Production and property taxes

 

$

0.41

 

$

0.47

 

$

(0.06

)

-12.8

%

Depreciation, depletion and amortization

 

$

1.58

 

$

1.85

 

$

(0.27

)

-14.6

%

 


* Not meaningful or applicable

 

Discussion of the components of the changes in our results for the nine months ended September 30, 2010 compared to September 30, 2009 and for the year ended December 31, 2009 compared to December 31,

 

34



 

2008 follows.  We have completed a significant number of acquisition and divestiture transactions of gas properties in 2010 and 2009 which affect the comparability of the results for the time periods presented below.  Details of our acquisition  and divesture transactions are included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Significant Acquisitions and Dispositions” and in Note 4 to the audited consolidated financial statements and Note 5 to the unaudited consolidated financial statements included in this Report.

 

Oil and natural gas sales- Revenues from sales of natural gas and oil and liquids increased to $4.5 million for the nine months ended September 30, 2010 from $4.2 million for the nine months ended September 30, 2009, an increase of 6.3%. This was primarily due to increased pricing for natural gas of $5.92 per Mcf inclusive of hedging activity for the nine months ended September 30, 2010 compared to $4.14 for the nine months ended September 30, 2009 partially offset by a decline in natural gas production as a result of the disposition of the Company’s Pennsylvania assets in March 2010.

 

To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed or variable swap contracts when our management believes that favorable future sales prices for our natural gas production can be secured.  Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-markets gains or losses, as well as realized gains or losses on the derivative instruments, are currently recognized in our results of operations.  The unrealized gains and losses represent the changes in the fair value of these swap agreements as the future strip prices fluctuate for the fixed price we will receive from future production.  For the nine months ended September 30, 2010 we had hedging gains of approximately $702,000 compared to hedging gains of approximately $82,000 for the nine months ended September 30, 2009.  Hedging gains and losses are included in natural gas and oil sales.

 

Lease operating expenses- Lease operating expenses decreased from approximately $801,000 for the nine months ended September 30, 2009 to approximately $767,000 for the nine months ended September 30, 2010 primarily due to the disposition of the Company’s Pennsylvania assets in March 2010.  On a per Mcfe basis, lease operating expenses increased from $.79 per Mcfe for the nine months ended September 30, 2009 to $1.02 for the nine months ended September 30, 2010 primarily due to start up operations in the Illinois Basin in 2010.

 

Transportation costs- Transportation costs decreased from approximately $268,000 for the nine months ended September 30, 2009 to approximately $226,000 for the nine months ended September 30, 2010 primarily due to the disposition of the Company’s Pennsylvania assets in March 2010.  On a per Mcfe basis, these expenses increased from $.26 per Mcfe for the nine months ended September 30, 2009 to $.30 per Mcfe for the nine months ended September 30, 2010.

 

Production and property taxes- Production and property taxes decreased from approximately $475,000 for the nine months ended September 30, 2009 to approximately $312,000 for the nine months ended September 30, 2010 primarily due to the decrease in natural gas sales for the nine months ended September 30, 2010 compared to 2009 and a decrease in ad valorem taxes on the Company’s West Virginia assets for the nine months ended September 30, 2010 compared to 2009 due to a reassessment of the Company’s ad valorem tax liability as of September 30, 2009, which increased the ad valorem taxes recorded in 2009.  On a per Mcfe basis, these expenses decreased from $.47 per Mcfe for the nine months ended September 30, 2009 to $.41 per Mcfe for the nine months ended September 30, 2010 primarily due to the reasons listed above.

 

Depreciation, depletion and amortization (DD&A)- DD&A decreased from $1.9 million for the nine months ended September 30, 2009 to $1.2 million for the nine months ended September 30, 2010

 

35



 

primarily due to the disposition of the Company’s Pennsylvania assets in March 2010 and a ceiling test write-down taken by the Company in the fourth quarter of 2009 which lowered the Company’s full cost pool resulting in a lower depletion rate per Mcfe.  On a per Mcfe basis, these expenses decreased from $1.85 per Mcfe for the nine months ended September 30, 2009 to $1.58 per Mcfe for the nine months ended September 30, 2010 primarily due to the reasons listed above.

 

General and administrative expenses- General and administrative expenses increased from $1.8 million for the nine months ended September 30, 2009 to $2.4 million for the nine months ended September 30, 2010 primarily due to increased administrative service charges from Nytis Exploration Company due to services performed in the disposition of the Company’s Pennsylvania assets in March 2010 and staff bonuses paid to NEC employees for the sale of the Company’s Pennsylvania assets in March 2010.

 

Interest expense- Interest expense decreased from approximately $883,000 for the nine months ended September 30, 2009 to approximately $291,000 for the nine months ended September 30, 2010 primarily due to the disposition of the Company’s Pennsylvania assets in March 2010 and using certain of the proceeds to pay down approximately $23.5 million of debt on the Company’s credit facility.

 

36



 

Results of Operations

 

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008.

 

The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2009 and 2008.  The following table sets forth, for the periods presented, selected historical statements of operations data.  The information contained in the table below should be read in conjunction with the audited consolidated financial statements contained in this Report.

 

 

 

Twelve Months Ended

 

 

 

 

 

 

 

December 31,

 

Increase /

 

Percent

 

(in thousands)

 

2009

 

2008

 

(Decrease)

 

Change

 

Revenue:

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

 

$

5,903

 

$

9,830

 

$

(3,927

)

-39.9

%

Interest income

 

38

 

38

 

 

0.0

%

Other income

 

334

 

433

 

(99

)

-22.9

%

Gain on sale of properties

 

 

 

 

*

 

Total revenues

 

$

6,275

 

$

10,301

 

$

(4,026

)

-39.1

%

 

 

 

 

 

 

 

 

 

 

Expenses:

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

1,135

 

$

1,138

 

$

(3

)

-0.3

%

Transportation costs

 

393

 

165

 

228

 

138.2

%

Production and property taxes

 

564

 

485

 

79

 

16.3

%

General and administrative

 

2,672

 

2,809

 

(137

)

-4.9

%

Depreciation, depletion and amortization

 

2,625

 

2,030

 

595

 

29.3

%

Accretion of asset retirement obligations

 

43

 

60

 

(17

)

-28.3

%

Impairment of oil and gas properties

 

16,077

 

 

16,077

 

*

 

Interest

 

1,167

 

1,412

 

(245

)

-17.4

%

Other expense

 

 

27

 

(27

)

-100.0

%

Total expenses

 

$

24,676

 

$

8,126

 

$

16,550

 

203.7

%

 

 

 

 

 

 

 

 

 

 

Production data:

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

1,336

 

1,054

 

282

 

26.8

%

Oil and liquids (Bbl)

 

870

 

530

 

340

 

64.2

%

Combined (MMcfe)

 

1,341

 

1,057

 

284

 

26.9

%

 

 

 

 

 

 

 

 

 

 

Average prices before effects of hedges:

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

4.23

 

$

9.18

 

$

(4.95

)

-53.9

%

Oil and liquids (per Bbl)

 

$

32.16

 

$

84.21

 

$

(52.05

)

-61.8

%

Combined (per Mcfe)

 

$

4.23

 

$

9.20

 

$

(4.97

)

-54.0

%

 

 

 

 

 

 

 

 

 

 

Average prices after effects of hedges:

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

4.40

 

$

9.29

 

$

(4.89

)

-52.6

%

Oil and liquids (per Bbl)

 

$

32.16

 

$

84.21

 

$

(52.05

)

-61.8

%

Combined (per Mcfe)

 

$

4.40

 

$

9.30

 

$

(4.90

)

-52.7

%

 

 

 

 

 

 

 

 

 

 

Average costs (per Mcfe):

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

0.85

 

$

1.08

 

$

(0.23

)

-21.3

%

Transportation costs

 

$

0.29

 

$

0.16

 

$

0.13

 

81.3

%

Production and property taxes

 

$

0.42

 

$

0.46

 

$

(0.04

)

-8.7

%

Depreciation, depletion and amortization

 

$

1.96

 

$

1.92

 

$

0.04

 

2.1

%

 


* Not meaningful or applicable

 

37



 

Oil and natural gas sales- Revenues from sales of natural gas and oil and liquids decreased to $5.9 million for 2009 from $9.8 million for 2009, a decrease of 39.9%. This was primarily due to decreased pricing for natural gas of $4.40 per Mcf inclusive of hedging activity for 2009 compared to $9.29 for 2008 partially offset by an increase in natural gas production of 26.8% for 2009 compared to 2008.

 

To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed or variable swap contracts when our management believes that favorable future sales prices for our natural gas production can be secured.  Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-markets gains or losses, as well as realized gains or losses on the derivative instruments, are currently recognized in our results of operations.  The unrealized gains and losses represent the changes in the fair value of these swap agreements as the future strip prices fluctuate for the fixed price we will receive from future production.  For 2009 we had hedging gains of approximately $227,000 compared to hedging gains of approximately $107,000 for 2008.  Hedging gains and losses are included in natural gas and oil sales.

 

Lease operating expenses- Lease operating expenses remained essentially flat in 2009 compared to 2008. On a per Mcfe basis, lease operating expenses decreased from $1.08 per Mcfe for 2008 to $.85 for 2009 primarily due to lower expenses on the Company’s Pennsylvania assets in 2009 compared to 2008.

 

Transportation costs- Transportation costs increased from approximately $165,000 for 2008 to approximately $393,000 for 2009 due to an increase of 26.8% of natural gas production and a greater utilization of firm transportation services in 2009 compared to 2008.  On a per Mcfe basis, these expenses increased from $.16 per Mcfe for 2008 to $.29 per Mcfe in 2009 primarily due to the reasons listed above.

 

Production and property taxes- Production and property taxes increased from approximately $485,000 for 2008 to approximately $564,000 for 2009 primarily due to an increase in ad valorem taxes for the Company’s properties in West Virginia due to a reassessment of the Company’s ad valorem tax liability as of December 31, 2009, which increased the ad valorem taxes recorded in 2009.  On a per Mcfe basis, these expenses decreased from $.46 per Mcfe for 2008 to $.42 per Mcfe for 2009 primarily due to a 26.8% increase in natural gas production in 2009 compared to 2008 partially offset by an increase in ad valorem taxes for the Company’s properties in West Virginia as discussed above.

 

Depreciation, depletion and amortization (DD&A)- DD&A increased from $2.0 million for 2008 to $2.7 million for 2009 primarily due to a 26.8% increase in natural gas production in 2009 compared to 2008.  On a per Mcfe basis, these expenses increased from $1.92 per Mcfe for 2008 to $1.96 per Mcfe for 2009.

 

General and administrative expenses- General and administrative expenses decreased from $2.8 million for 2008 to $2.7 million for 2009 primarily due to decreased staff levels in 2009 compared to 2008 partially offset by increased administrative service charges from Nytis Exploration Company due to services performed in the rationalization of the Company’s Pennsylvania assets in the fourth quarter of 2008.

 

Interest expense- Interest expense decreased from $1.4 million in 2008 to $1.2 million in 2009 primarily due to lower interest rates charged under the Company’s credit facility.

 

Liquidity and Capital Resources

 

Our exploration, development, and acquisition activities require us to make significant operating and capital expenditures. Historically, we have used cash flow from operations and our bank credit facilities as our primary sources of liquidity, and, as market conditions have permitted, we have engaged in asset monetization transactions, such as the divestiture of our Pennsylvania assets.

 

38



 

Changes in the market prices for natural gas directly impact our level of cash flow generated from operations. Natural gas is expected to make up approximately 99% of our hydrocarbon production in 2010 and, as a result, our operations and cash flow are more sensitive to fluctuations in the market price for natural gas than to fluctuations in the market price for oil and liquids. We employ a commodity hedging strategy as an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. For the nine months ended September 30, 2010, we hedged approximately 48% of our production at a weighted average price of $5.33 per MMBtu. This level of hedging provided certainty of the cash flow for a portion of our production for the nine months ended September 30, 2010. However, future hedging activities may result in reduced income or even financial losses to us. SeeRisk Factors— Our future use of hedging arrangements could result in financial losses or reduce income,” for further details of the risks associated with our hedging activities. In the future, we may determine to increase or decrease our hedging positions. As of September 30, 2010, our derivative counterparty was party to our credit facility, or its affiliates.  For further information concerning our derivative contracts. SeeQuantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk,” below.

 

The other primary source of liquidity is our U.S. credit facility (described below), which had an aggregate borrowing base of $24.1 million as of December 31, 2009 and $8.0 million at September 30, 2010; the reduction in our borrowing base was due to the divestiture of our Pennsylvania assets and the effects of lower natural gas prices.  These facilities are used to fund daily operations and to fund acquisitions and refinance debt, as needed and if available. The credit facilities are secured by a portion of our assets and mature in May 2012. See—“Bank Credit Facilities” below for further details. We had $24.0 million drawn on our credit facilities as of December 31, 2009 and $2.1 million drawn on September 30, 2010.

 

Our ability to access the debt and equity capital markets on economical terms is affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value of our equity securities, prevailing commodity prices, and other macroeconomic factors outside of our control.

 

We believe that our current cash and cash equivalents, cash flows provided by operating activities, and $5.9 million of funds available under our credit facility will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures (other than the potential acquisition of additional natural gas and oil properties), and our contractual obligations. However, if our revenue and cash flow decrease in the future as a result of a deterioration in domestic and global economic conditions or a significant decline in commodity prices, we may elect to reduce our planned capital expenditures. We believe that this financial flexibility to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations should economic conditions deteriorate. SeeRisk Factors,” for a discussion of the risks and uncertainties that affect our business and financial and operating results.

 

Bank Credit Facility

 

NEC has a bank credit facility which consists of a $50.0 million credit facility (the “Credit Facility”) with Bank of Oklahoma. The Credit Facility will mature in May 2012 and is guaranteed by Nytis USA. Our availability under the Credit Facility is governed by a borrowing base (the “Borrowing Base”), which is currently at $8.0 million. The determination of the Borrowing Base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of our natural gas properties in accordance with the lenders’ customary practices for natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. The next redetermination of the Borrowing Base is expected to occur in May 2011. In addition to the semi-annual redeterminations, Nytis and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the Borrowing Base redetermined.

 

39



 

A lowering of the Borrowing Base could require us to repay indebtedness in excess of the Borrowing Base in order to cover the deficiency.

 

The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base.  Interest rates are based on either an Alternative Base Rate or LIBOR.  The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point.  The portion based on LIBOR is determined by the rate per annum equal to LIBOR plus between 2.5% and LIBOR plus 3.25% for each LIBOR tranche. For all debt outstanding regardless if the loan is based on an Alternative Base Rate or LIBOR, there is a minimum floor of 4.5% per annum.

 

The Credit Facility includes terms that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and requires satisfaction of a current ratio (the ratio of current assets to current liabilities) of 1.0 to 1.0 and a maximum Funded Debt Ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges)) of 3.5 to 1.0, for the most recently completed four consecutive fiscal quarters as of the end of any fiscal quarter.  If we were to fail to perform our obligations under these covenants or other covenants and obligations, it could cause an event of default and the Credit Facility could be terminated and amounts outstanding could be declared immediately due and payable by the lenders, subject to notice and, in certain cases, cure periods. Such events of default include non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, change of control, and a failure of the liens securing the Credit Facility.  In addition, bankruptcy and insolvency events with respect to Nytis or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facility.

 

Under the Credit Facility, we are required to mortgage and grant a security interest in 80% of the present value of our proved natural gas properties. Under certain circumstances, we could be obligated to pledge additional assets as collateral.

 

Of the $50.0 million total nominal amount under the Credit Facility, Bank of Oklahoma held 100% of the total commitments.

 

As of December 31, 2009 and September 30, 2010, there were $24.0 million and $2.1 million, respectively, borrowings under our Credit Facility.

 

In addition, the credit facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements and agreements designated to protect the Company against changes in interest and currency exchange rates.  The maximum amount of credit on this line is $2.7 million.

 

Historical Cash Flow

 

Net cash provided by (used in) operating activities, net cash provided by (used in) investing activities, and net cash provided by (used in) financing activities for the nine months ended September 30, 2010 and 2009 and for the years ended December 31, 2009 and 2008  were as follows:

 

40



 

OPERATING CASH FLOWS

 

 

 

Nine Months Ended

 

 

 

 

 

 

 

September 30,

 

Year Ended December 31,

 

(in thousands)

 

2010

 

2009

 

2009

 

2008

 

 

 

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in) operating activities

 

$

(2,725

)

$

1,538

 

$

2,043

 

$

5,542

 

Net cash provided by (used in) investing activities

 

$

26,585

 

$

(206

)

$

(1,071

)

$

(6,628

)

Net cash provided by (used in) financing activities

 

$

(23,049

)

$

(1,726

)

$

(1,459

)

$

1,592

 

 

Net cash provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital.  The decrease in operating cash flows operating activities of $4.3 million for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009 was primarily due to a reduction of $2.5 million in accounts payable for the nine months ended September 30, 2010 compared to an increase in accounts payable of approximately $633,000 for the nine months ended September 30, 2009.  The decrease of $3.5 million in operating cash flows in 2009 as compared to 2008 was primarily due to lower commodity prices partially offset by increased natural gas production in 2009 as compared to 2008.

 

Net cash provided by (used in) investing activities is primarily comprised of the acquisition, exploration, and development of natural gas properties net of dispositions of natural gas properties. The increase in investing cash flows $26.8 million for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009 was primarily due to the proceeds received by the disposition of the Company’s Pennsylvania assets in 2010.  The increase in investing cash flows of $5.6 million for 2009 as compared to 2008 was primarily due to a $3.2 million decrease in cash used for the acquisition, exploration and development of oil and gas properties and a $2.4 million increase in proceeds from the sale of oil and gas properties.

 

The decrease in financing cash flows of $21.3 million for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009 was primarily due to the net repayments of bank borrowings of $21.9 million in 2010.  The decrease in financing cash flows of $3.1 for 2009 as compared to 2008 was primarily due to the net repayments of bank borrowings of $1.5 million in 2009 as compared to net additional bank borrowings of $1.6 million in 2008.  SeeCapital Expenditures” below for more detail on our capital expenditures.

 

Capital Expenditures

 

Capital expenditures for the nine months ended September 30, 2010 and 2009, and for the years ended December 31, 2009 and 2008 are summarized in the following table:

 

 

 

Nine Months Ended

 

Year Ended

 

 

 

September 30,

 

December 31,

 

(in thousands)

 

2010

 

2009

 

2009

 

2008

 

 

 

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition of oil and gas properties

 

 

 

 

 

 

 

 

 

Unevaluated properties

 

$

19

 

$

196

 

$

29

 

$

635

 

Oil and gas properties

 

$

1,319

 

$

 

$

 

$

 

Drilling and development

 

1,866

 

1,905

 

3,105

 

6,313

 

Pipeline and gathering (1)

 

168

 

284

 

465

 

 

Other

 

 

75

 

75

 

10

 

Total capital expenditures

 

$

3,372

 

$

2,460

 

$

3,674

 

$

6,958

 

 


Note:

(1)                                  Includes an investment in a joint venture which is a gas gathering plant.

 

41



 

Capital expenditures reflected in the table above differ from the amounts shown in the statements of cash flows in the consolidated financial statements because amounts reflected in the table include changes in accounts payable from the previous reporting period for capital expenditures, while the amounts in the statements of cash flow in the consolidated financial statements are presented on a cash basis.

 

Due to the significant downturn in the overall economy in late 2008 and its impact on the price for natural gas, we chose to reduce our capital expenditures and drilling activity in 2009 by keeping our exploration and development capital spending near our cash flow in 2009. As a result of increased liquidity in 2010 from our divestiture program, higher commodity prices, and focusing our development on areas with expected high growth potential, we have increased our acquisition activity in 2010 compared to 2009. Primary factors impacting the level of our capital expenditures include natural gas prices, the volatility in these prices, the cost and availability of oil field services, general economic and market conditions, and weather disruptions.

 

Off-balance Sheet Arrangements

 

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2009, the off-balance sheet arrangements and transactions that we have entered into include (i)  operating lease agreements and (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation commitments and derivative contracts that are sensitive to future changes in commodity prices or interest rates. We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

 

Critical Accounting Policies, Estimates, Judgments, and Assumptions

 

Full Cost Method of Accounting

 

The accounting for our business is subject to special accounting rules that are unique to the natural gas and oil industry. There are two allowable methods of accounting for natural gas and oil business activities: the full cost method and the successful efforts method. The differences between the two methods can lead to significant variances in the amounts reported in financial statements. We have elected to follow the full cost method, which is described below.

 

Under the full cost method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) are capitalized. The fair value of estimated future costs of site restoration, dismantlement, and abandonment activities is capitalized, and a corresponding asset retirement obligation liability is recorded.

 

Capitalized costs applicable to each full cost center are depleted using the units of production method based on conversion to common units of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves or future development costs are accounted for prospectively in the depletion calculations. Based on this accounting policy, our December 31, 2009 reserves estimates were used for our 2009 depletion calculation. These reserves estimates were calculated in accordance with the SEC’s “Modernization of Natural gas Reporting” rules, which were first effective for 2009 year-end reporting. SeeDescription of Business—Reserves” and Notes 1 and 2 to the audited consolidated financial statements included in this report for a more complete discussion of these rules and our estimated proved reserves as of December 31, 2009.

 

42



 

Companies that use the full cost method of accounting for natural gas and oil exploration and development activities are required to perform a ceiling test for each cost center. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation. The test determines a limit, or ceiling, on the book value of natural gas properties. That limit is basically the after tax present value of the future net cash flows from proved natural gas reserves. This ceiling is compared to the net book value of the natural gas and oil properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash write-down is required. Our December 31, 2009 ceiling test calculation, which included a ceiling based on natural gas and oil reserves calculated using twelve-month average prices pursuant to the SEC’s “Modernization of Natural gas Reporting” rules which were effective for the first time as of December 31, 2009, resulted in the Company’s natural gas and oil properties exceeding the ceiling limitation by approximately $16.1 million, and accordingly the Company took a non-cash charge to income for approximately $16.1 million for the year ended December 31, 2009.

 

In countries or areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion, and amortization, and the application of the ceiling limitation. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to individually assess properties whose costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool.

 

Under the alternative successful efforts method of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, exploratory dry holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property-by-property basis. Impairments are also assessed on a property-by-property basis and are charged to expense when assessed.

 

The full cost method is used to account for our natural gas and oil exploration and development activities, because we believe it appropriately reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves.

 

Natural Gas Reserve Estimates

 

Our estimates of proved reserves are based on the quantities of natural gas and oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent uncertainty in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our natural gas and oil properties, the quantity of reserves could significantly impact our DD&A

 

43



 

expense. Our natural gas and oil properties are also subject to a “ceiling test” limitation based in part on the quantity of our proved reserves.

 

Reference should be made to “Reserves” under “Description of Business,” and “Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves,” under “Risk Factors”.

 

Accounting for Derivative Instruments

 

We recognize all derivative instruments as either assets or liabilities at fair value. Under the provisions of authoritative derivative accounting guidance, we may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (a “fair value hedge”) or against exposure to variability in expected future cash flows (a “cash flow hedge”). The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of operations, because changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings. We have elected not to use hedge accounting and as a result, all changes in the fair values of our derivative instruments are recognized in natural gas and oil sales in our Consolidated Statements of Operations.

 

Estimating the fair values of our derivative instruments requires the exercise of substantial judgment.  In determining the fair value of our derivative instruments, we utilize observable inputs that market participants use in pricing the asset or liability based on market data obtained from sources independent of the Company.  The values we report in our financial statements change as these estimates are revised to reflect changes in market conditions or other factors, many of which are beyond our control.

 

Due to the volatility of natural gas prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period and we expect the volatility to continue. Actual gains or losses recognized related to our commodity derivative instruments will likely differ from those estimated at September 30, 2010 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

 

Valuation of Deferred Tax Assets

 

We use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are determined based on differences between the financial statement carrying values of assets and liabilities and their respective income tax bases (temporary differences). Income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect on income tax assets and liabilities of a change in tax rates is included in earnings in the period in which the change is enacted. The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.

 

In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable

 

44



 

income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both negative and positive. Negative evidence considered by management primarily included a recent history of book losses which were driven entirely from ceiling test write-downs, which are not fair value based measurements. Positive evidence considered by management included forecasted book income over a reasonable period of time and the utilization of substantially all of our net operating loss (“NOL”) carryforwards in 2010 due primarily to a substantial tax gain associated with the disposition of the Company’s Pennsylvania assets. Based upon the evaluation of what management determined to be relevant evidence, we recorded a $4.8 million deferred tax benefit for the year ended December 31, 2009 that will be utilized in 2010 . See Note 7 to the audited consolidated financial statements included in this report.

 

The primary evidence utilized to determine that it is more likely than not that our deferred tax assets will be realized is management’s expectation of future book income over the next several years, as well as the significant tax gain recognized in connection with the sale of our Pennsylvania assets during 2010, which allowed us to realize the majority of our deferred tax assets that were attributable to NOL carryforwards. With all of our NOL carryforwards substantially used, our deferred tax asset position is now almost exclusively driven by the accelerated reduction in the book value of our natural gas assets relative to our tax basis due to the use of the full cost method of accounting for natural gas and oil properties and the difference between the book and tax values of our Pennsylvania assets that were sold in 2010.

 

Asset Retirement Obligations

 

We have obligations to remove tangible equipment and restore locations at the end of the natural gas production operations. Estimating the future restoration and removal costs, or asset retirement obligations, is difficult and requires management to make estimates and judgments, because most of the obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

 

Inherent in the calculation of the present value of our asset retirement obligations (“ARO”) are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the natural gas property balance. Increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations.

 

Impact of Recently Issued Accounting Pronouncements.

 

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-06, Improving Disclosures about Fair Value Measurements, which amends Accounting Standards Codification 820, Fair Value Measurements and Disclosures.  The intent of this update is to improve disclosure requirement related to fair value measurements and disclosures.  New disclosures are required regarding transfers in and out of Levels 1 and 2 and activity within Level 3 fair value measurements, as well as clarification of existing disclosures regarding the level of disaggregation and disclosures about fair value measurement inputs and valuation techniques.  With the exception of disclosures regarding purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, the new disclosures and clarifications of existing disclosures were effective as of January 1, 2010, and all new disclosure requirements have been incorporated.  The disclosures regarding the roll forward of activity in Level 3 fair value measurements are effective for the Company beginning January 1, 2011.  The adoption of these disclosure requirements did not have a material impact on the Company’s financial statements.

 

45



 

Item 3.    Properties

 

Drilling Activities

 

The following table summarizes the number of wells drilled during 2009 and 2008, and for the nine months ended September 30, 2010.  Gross wells reflect the sum of all wells in which we own an interest.  Net wells reflect the sum of our working interests in gross wells.  As of September 30, 2010, we had no wells in progress.

 

 

 

Nine Months
Ended

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

Year Ended December 31,

 

 

 

2010

 

2009

 

2008

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

12.0

 

4.7

 

11.0

 

5.2

 

18.0

 

12.1

 

Dry

 

 

 

1.0

 

0.5

 

 

 

Total Development Wells

 

12.0

 

4.7

 

12.0

 

5.7

 

18.0

 

12.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

 

 

 

 

 

Dry

 

 

 

 

 

1.0

 

1.0

 

Total Exploratory Wells

 

 

 

 

 

1.0

 

1.0

 

 

A non-productive well is a well found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well; also known as a dry well or dry hole.

 

Natural Gas and Oil Wells and Acreage

 

Productive Wells

 

Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. The following table summarizes our productive wells as of September 30, 2010.

 

 

 

Total

 

 

 

Producing Wells

 

 

 

Gross

 

Net

 

 

 

 

 

 

 

Gas

 

368

 

156

 

Oil

 

14

 

14

 

Total

 

382

 

170

 

 

Acreage

 

The following table summarizes developed and undeveloped acreage in which we owned a working interest or held an exploration license as of September 30, 2010. A majority of our developed acreage is subject to mortgage liens securing our bank credit facilities. Acreage related to royalty, overriding

 

46



 

royalty, and other similar interests is excluded from this summary, as well as acreage related to any options held by us to acquire additional leasehold interests.

 

 

 

Developed

 

Undeveloped

 

Total

 

 

 

Acres

 

Acres

 

Acres

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Indiana

 

160

 

160

 

82,713

 

62,289

 

82,873

 

62,449

 

Illinois

 

6,080

 

3,040

 

54,738

 

29,646

 

60,818

 

32,686

 

Kentucky

 

5,809

 

4,722

 

65,917

 

51,147

 

71,726

 

55,869

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ohio

 

558

 

558

 

6,640

 

6,640

 

7,198

 

7,198

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tennessee

 

 

 

100,000

 

95,000

 

100,000

 

95,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West Virginia

 

5,185

 

4,948

 

10,997

 

5,713

 

16,182

 

10,661

 

Total

 

17,792

 

13,428

 

321,005

 

250,435

 

338,797

 

263,863

 

 

Undeveloped Acreage Expirations

 

The following table sets forth the number of gross and net undeveloped acres by state as of September 30, 2010, the leases for which are scheduled to expire over the following three years unless production is established within the spacing unit covering the acreage prior to the expiration date or the Company extends the terms of a lease by paying delay rentals to the lessor.

 

 

 

2011

 

2012

 

2013

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Indiana

 

20,993

 

11,603

 

1,505

 

752

 

 

 

Illinois

 

13,090

 

6,545

 

656

 

328

 

 

 

Kentucky

 

75

 

75

 

4,528

 

4,262

 

259

 

259

 

Ohio

 

 

 

51

 

51

 

22

 

22

 

Tennessee

 

 

 

 

 

 

 

West Virginia

 

 

 

 

 

 

 

Total

 

34,158

 

18,223

 

6,740

 

5,393

 

281

 

281

 

 

Production, Average Sales Prices, and Production Costs

 

The following table reflects production, average sales price, and production cost information for the years ended December 31, 2009, and 2008, and for the nine months ended September 30, 2010 and 2009.

 

47



 

 

 

Nine Months Ended

 

Year Ended

 

 

 

September 30,

 

December 31,

 

 

 

2010

 

2009

 

2009

 

2008

 

Production data:

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

750

 

1,015

 

1,336

 

1,054

 

Oil and condensate (Bbl)

 

990

 

601

 

870

 

530

 

Combined (MMcfe)

 

756

 

1,019

 

1,341

 

1,057

 

Gas and oil production revenue (in thousands)

 

$

4,492

 

$

4,227

 

$

5,902

 

$

9,830

 

Prices:

 

 

 

 

 

 

 

 

 

Average sales price before effects of hedging (per Mcfe)

 

$

5.02

 

$

4.07

 

$

4.23

 

$

9.20

 

Average realized sales price after effects of hedges (per Mcfe)

 

$

5.94

 

$

4.07

 

$

4.40

 

$

9.30

 

Average costs per Mcfe:

 

 

 

 

 

 

 

 

 

Lease operating costs

 

$

1.02

 

$

0.79

 

$

0.85

 

$

1.08

 

Transportation costs

 

$

0.30

 

$

0.26

 

$

0.29

 

$

0.16

 

Production and property taxes

 

$

0.41

 

$

0.47

 

$

0.42

 

$

0.46

 

 

Marketing and Delivery Commitments

 

Our natural gas production is generally sold on a month-to-month basis in the spot market, priced in reference to published indices. We believe that the loss of one or more of our natural gas purchasers would not have a material adverse effect on our ability to sell our production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption. We had no material delivery commitments as of September 30, 2010.

 

Competition

 

We encounter competition in all aspects of our business, including acquisition of properties and oil and natural gas leases, marketing oil and natural gas, obtaining services and labor, and securing drilling rigs and other equipment and materials necessary for drilling and completing wells. Our ability to increase reserves in the future will depend on our ability to generate successful prospects on our existing properties, execute on major development drilling programs, and acquire additional leases and prospects for future development and exploration. A large number of the companies that we compete with have substantially larger staffs and greater financial and operational resources than we have. Because of the nature of our natural gas assets and management’s experience in exploiting our reserves and acquiring properties, management believes that we effectively compete in our markets. SeeRisk Factors— Competition in the natural gas and oil industry is intense, making it more difficult for us to acquire properties, market natural gas and oil and secure trained personnel.

 

Regulation

 

Our operations are subject to various U.S. federal, state, and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Matters subject to current governmental regulation and/or pending legislative or regulatory changes include the discharge or other release into the environment of wastes and other substances in connection with drilling and production

 

48



 

activities (including fracture stimulation operations), bonds or other financial responsibility requirements to cover drilling risks and well plugging and abandonment, reclamation or restoration costs, reports concerning our operations, the spacing of wells, unitization and pooling of properties, taxation, and the use of derivative hedging instruments. Failure to comply with the laws and regulations in effect from time to time may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that could delay, limit, or prohibit certain of our operations. In the past, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and gas, oil and gas conservation commissions and other agencies may restrict the rates of flow of wells below actual production capacity, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.  Further, a significant spill from one of our facilities could have a material adverse effect on our results of operations, competitive position, or financial condition. The laws in the U.S., including state laws, regulate, among other things, the production, handling, storage, transportation, and disposal of natural gas and oil, by-products from each, and other substances and materials produced or used in connection with our operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

 

In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as Nytis, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (“FERC”), in contravention of rules prescribed by the FERC. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas in respect of EPAct 2005.

 

In December 2007, the FERC issued rules requiring that any market participant, including a producer such as Nytis, that engages in physical sales for resale or purchases for resale of natural gas that equal or exceed 2.2 million MMBtus during a calendar year must annually report such sales or purchases to the FERC, beginning on May 1, 2009. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation. On September 18, 2008 the FERC issued its order on rehearing, which largely approved the existing rules, except the FERC exempted from the reporting requirement certain types of purchases and sales, including purchases and sales of unprocessed natural gas and bundled sales of natural gas made pursuant to state regulated retail tariffs. Also, the FERC clarified that other end use purchases and sales are not exempt from the reporting requirements. The monitoring and reporting required by the new rules will likely increase our administrative costs. Nytis does not anticipate it will be affected any differently than other producers of natural gas.

 

Additional proposals and proceedings that might affect the natural gas industry are regularly considered by Congress, the states, the FERC, and the courts. For instance, legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations—an important process used in the completion of our natural gas wells—to regulation under the Safe Drinking Water Act. If adopted, this legislation could establish an additional level of regulation, and impose additional costs, on our operations. We cannot predict when or whether any such proposal, or any additional new legislative or regulatory proposal, may become effective. No material portion of Nytis’s

 

49



 

business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

 

Environmental

 

As an operator of natural gas and oil properties in the U.S., we are subject to stringent national, state, provincial, and local laws and regulations relating to environmental protection as well as controlling the manner in which various substances, including wastes generated in connection with exploration, production, and transportation operations, are released into the environment. Compliance with these laws and regulations can affect the location or size of wells and facilities, prohibit or limit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties when production ceases. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, or criminal penalties, imposition of remedial obligations, incurrence of capital or increased operating costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production activities or that constrain the disposal of substances generated by oil field operations.

 

We currently operate or lease, and have in the past operated or leased, a number of properties that for many years have been used for the exploration and production of natural gas and oil. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to laws and regulations imposing joint and several liability and strict liability without regard to fault or the legality of the original conduct that could require us to remove previously disposed wastes or remediate property contamination, or to perform well or pit closure or other actions of a remedial nature to prevent future contamination.

 

In 2009, the U.S. House of Representatives passed a bill to control and reduce the emission of domestic greenhouse gases through the grant of emission allowances which would gradually be decreased over time.  Although similar bills were considered in the U.S. Senate, such legislation lacked bipartisan support in the current Congress. Despite the lack of federal legislation, nearly half of the states, either individually or through multi-state initiatives, have already begun implementing legal measures to reduce greenhouse gas emissions. Also, the U.S. Supreme Court held in Massachusetts et al. v. EPA (2007) that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act, which could result in future regulation of greenhouse gas emissions from stationary and non-stationary sources, even if Congress does not adopt new legislation specifically addressing such emissions. In December 2009, the U.S. Environmental Protection Agency (“EPA”) published its findings that emissions of greenhouse gases present an endangerment to public health and the environment because such emissions, according to the EPA, are contributing to warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to implement regulations that would restrict greenhouse gas emissions under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted regulations that require a reduction of greenhouse gas emissions from motor vehicles and has proposed additional regulations to further restrict such emissions.  The EPA has also finalized regulations that require certain U.S. facilities, including certain petroleum and natural gas facilities, to report their greenhouse gas emissions beginning on January 1, 2011. The adoption and implementation of these regulations impacts our business, and any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the natural gas that we produce.

 

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We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we are in substantial compliance with applicable environmental laws and regulations in effect at the present time and that continued compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance that we will not be adversely affected in the future. We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the U.S. Although we maintain pollution insurance against the costs of cleanup operations, public liability, and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future.

 

Item 4. Security Ownership of Certain Beneficial Owners and Management.

 

As a result of the Merger, the Company now has 47,518,739 shares of common stock outstanding as of the date of this Report.  Because approximately 99% of the outstanding common shares represent the shares issued by the Company at the closing of the Merger, the Merger has resulted in a change in control of the Company.  The following sets forth certain information about the number of common shares owned by (i) each person (including any group) known to us that owns five percent or more of the common shares (the only class of the Company’s voting securities, (ii) each of our directors and executive officers, and (iii) all executive officers and directors as a group.  Unless otherwise indicated, the shareholders possess sole voting and investment power with respect to the shares shown.

 

Name and Address of Beneficial
Owner

 

Amount of Beneficial
Ownership(1)

 

Percent of Class(2)

 

 

 

 

 

 

 

5% Stockholders

 

 

 

 

 

 

 

 

 

 

 

Yorktown Energy Partners V, L.P.

410 Park Avenue,

19th Floor

New York, NY 10022

 

17,938,309

 

37.8

%

 

 

 

 

 

 

Yorktown Energy Partners VI, L.P.,

410 Park Avenue,

19th Floor

New York, NY 10022

 

17,938,309

 

37.8

%

 

 

 

 

 

 

RBCP Energy Fund Investments, LP

c/o Cadent Energy Partners, LLC

4 High Ridge Park, Suite 303

Stamford, CT 06905

 

8,153,777

 

17.2

%

 

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Name of
Beneficial Owner

 

Amount of
Beneficial
Ownership(1)

 

Percent of
Class(2)

 

Options and
Warrants
Exercisable
Within 60 Days

 

Total

 

Percent of
Class — Total

 

 

 

 

 

 

 

 

 

 

 

 

 

Executive Officers and Directors

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Bryan H. Lawrence, Director(3)

 

35,876,618

 

75.5

%

 

35,876,618

 

75.5

%

 

 

 

 

 

 

 

 

 

 

 

 

Peter A. Leidel, Director (4)

 

35,876,618

 

75.5

%

 

35,876,618

 

75.5

%

 

 

 

 

 

 

 

 

 

 

 

 

Paul G.  McDermott, Director (5)

 

8,153,777

 

17.2

%

32,616

 

8,186,392

 

17.2

%

 

 

 

 

 

 

 

 

 

 

 

 

David H. Kennedy, Director

 

163,076

 

*

 

73,384

 

236,460

 

*

 

 

 

 

 

 

 

 

 

 

 

 

 

Patrick R. McDonald, Director, President and Chief Executive Officer(6)

 

1,991,153

 

4.2

%

2,446,133

 

4,437,286

 

8.9

%

 

 

 

 

 

 

 

 

 

 

 

 

Kevin D. Struzeski, Chief Financial Officer, Treasurer and Secretary

 

407,689

 

*

 

163,076

 

570,765

 

1.2

%

 

 

 

 

 

 

 

 

 

 

 

 

Mark D. Pierce, General Manager of NEC

 

40,769

 

*

 

 

40,769

 

*

 

 

 

 

 

 

 

 

 

 

 

 

 

All directors and executive officers as a group (seven persons) (7)

 

46,633,082

 

98.1

%

2,715,209

 

49,348,291

 

98.2

%

 


* less than 1%

 

(1)  Under Rule 13d-3, a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares; and (ii) investment power, which includes the power to dispose or direct the disposition of shares.  Certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares).  In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares (for example, upon exercise of an option) within 60 days of the date as of which the information is provided.  In computing the percentage ownership of any person, the amount of shares outstanding is deemed to include the amount of shares beneficially owned by such person (and only such person) by reason of these acquisition rights.

 

(2)  Percentages are rounded to the nearest one-tenth of one percent.  The percentage of class is based on 47,518,739 shares of common stock issued and outstanding as of the date of this Report.

 

(3)  Includes 17,938,309 shares that will be owned by Yorktown Energy Partners V, LP and 17,938,309 shares that owned by Yorktown Energy Partners VI, LP over which Mr. Lawrence and Mr. Leidel have voting and investment power.

 

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(4)  Includes 17,938,309 shares owned by Yorktown Energy Partners V, LP and 17,938,309 shares that will be owned by Yorktown Energy Partners VI, LP over which Mr. Leidel and Mr. Lawrence have voting and investment power.

 

(5)  Includes 8,153,777 shares owned by RBCP Energy Fund Investments, LP, over which Mr. McDermott has voting and investment power.

 

(6)  Includes (i) 482,704 shares owned by McDonald Energy, LLC over which Mr. McDonald has voting and investment power, and (ii) stock purchase warrants held by McDonald Energy, LLC exercisable for 2,446,133 shares of common stock.