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GASCO ENERGY 10-Q 2011

Documents found in this filing:

  1. 10-Q
  2. Ex-10.4
  3. Ex-31.1
  4. Ex-31.2
  5. Ex-32.1
  6. Ex-32.2
  7. Ex-32.2

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

(Mark One)

 

x

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

 

 

For the quarterly period ended September 30, 2011

 

OR

 

 

o

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

 

For the transition period from         to        

 

Commission File Number: 001-32369

 

GASCO ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

Nevada

 

98-0204105

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

8 Inverness Drive East, Suite 100, Englewood, Colorado

 

80112

(Address of principal executive offices)

 

(Zip Code)

 

(303) 483-0044

(Registrant’s telephone number, including area code)

 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

 

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

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer x

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

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

 

Number of common shares outstanding as of November 1, 2011: 168,010,815

 

 

 



Table of Contents

 

Table of Contents

 

PART I — FINANCIAL INFORMATION

 

 

 

Item 1.

Financial Statements (Unaudited)

3

 

Condensed Consolidated Balance Sheets

3

 

Condensed Consolidated Statements of Operations

5

 

Condensed Consolidated Statements of Cash Flows

7

 

Notes to Condensed Consolidated Financial Statements

8

 

 

 

Item 2.

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

 28

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

45

 

 

 

Item 4.

Controls and Procedures

47

 

 

 

PART II —OTHER INFORMATION

 

 

 

Item 1.

Legal Proceedings

47

 

 

 

Item 1A.

Risk Factors

47

 

 

 

Item 6.

Exhibits

48

 

Please refer to the section entitled “Cautionary Statement Regarding Forward-Looking Statements” at the end of Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (“Quarterly Report”) for a discussion of factors that could affect the outcome of forward-looking statements used in this Quarterly Report. Please also refer to the “Glossary of Natural Gas and Oil Terms” following the “Cautionary Statement Regarding Forward-Looking Statements” for the definition of certain industry terms used in this Quarterly Report.

 

2



Table of Contents

 

ITEM I — FINANCIAL STATEMENTS

 

PART 1 — FINANCIAL INFORMATION

 

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

September 30,

 

December 31,

 

 

 

2011

 

2010

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

9,498,846

 

$

1,994,542

 

Accounts receivable

 

 

 

 

 

Joint interest billings

 

665,509

 

1,296,719

 

Revenue

 

2,123,444

 

2,423,114

 

Inventory

 

1,770,494

 

1,773,079

 

Derivative instruments

 

318,143

 

193,959

 

Prepaid expenses

 

30,863

 

121,637

 

Total

 

14,407,299

 

7,803,050

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT, at cost

 

 

 

 

 

Oil and gas properties (full cost method)

 

 

 

 

 

Proved properties

 

266,892,392

 

263,104,555

 

Unproved properties

 

36,394,721

 

35,941,100

 

Facilities and equipment

 

1,429,026

 

1,120,134

 

Furniture, fixtures and other

 

173,810

 

240,659

 

Total

 

304,889,949

 

300,406,448

 

Less accumulated depletion, depreciation, amortization and impairment

 

(233,385,892

)

(230,701,994

)

Total

 

71,504,057

 

69,704,454

 

 

 

 

 

 

 

NONCURRENT ASSETS

 

 

 

 

 

Deposit

 

639,500

 

639,500

 

Derivative instruments

 

53,772

 

 

Note receivable

 

500,000

 

500,000

 

Deferred financing costs

 

1,451,001

 

1,363,425

 

Total

 

2,644,273

 

2,502,925

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

88,555,629

 

$

80,010,429

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

3



Table of Contents

 

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

(Unaudited)

 

 

 

September 30,

 

December 31,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable

 

$

938,392

 

$

2,111,192

 

Revenue payable

 

3,275,575

 

2,598,693

 

Advances from joint interest owners

 

101,742

 

1,164,414

 

Current portion of long-term debt

 

8,544,969

 

 

5.5% Convertible Senior Notes due 2011

 

400,000

 

400,000

 

Accrued interest

 

1,218,311

 

591,751

 

Accrued expenses

 

398,755

 

1,191,000

 

Total

 

14,877,744

 

8,057,050

 

 

 

 

 

 

 

NONCURRENT LIABILITIES

 

 

 

 

 

5.5% Convertible Senior Notes due 2015, net of unamortized discount of $23,421,435 as of September 30, 2011 and $25,682,482 as of December 31, 2010

 

21,746,565

 

19,485,516

 

Long-term debt

 

 

6,544,969

 

Deferred income from sale of assets

 

2,716,242

 

2,868,081

 

Asset retirement obligation

 

1,197,924

 

1,119,561

 

Derivative instruments

 

3,932,500

 

 

Total

 

29,593,231

 

30,018,127

 

 

 

 

 

 

 

STOCKHOLDERS’ EQUITY

 

 

 

 

 

Series B Convertible Preferred stock - $0.001 par value; 20,000 shares authorized; zero shares outstanding

 

 

 

Series C Convertible Preferred stock - $0.001 par value; 2,000,000 shares authorized; 191,000 shares outstanding as of September 30, 2011 and 225,600 shares outstanding as of December 31, 2010

 

191

 

226

 

Common stock - $.0001 par value; 600,000,000 shares authorized; 168,084,515 shares issued and 168,010,815 outstanding as of September 30, 2011 and 121,255,748 shares issued and 121,182,048 outstanding as of December 31, 2010

 

16,808

 

12,126

 

Additional paid-in capital

 

262,300,911

 

257,327,315

 

Accumulated deficit

 

(218,102,961

)

(215,274,120

)

Less cost of treasury stock of 73,700 common shares

 

(130,295

)

(130,295

)

Total

 

44,084,654

 

41,935,252

 

 

 

 

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

$

88,555,629

 

$

80,010,429

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

4



Table of Contents

 

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

Three Months Ended
September 30,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

Gas

 

$

3,946,424

 

$

4,029,912

 

Oil

 

630,703

 

671,775

 

Total

 

4,577,127

 

4,701,687

 

 

 

 

 

 

 

OPERATING EXPENSES

 

 

 

 

 

Lease operating

 

2,082,081

 

1,422,397

 

Transportation and processing

 

444,561

 

801,938

 

Depletion, depreciation, amortization and accretion

 

950,396

 

817,986

 

Loss on sale of assets, net

 

92,020

 

79,837

 

General and administrative

 

1,025,694

 

1,225,048

 

Total

 

4,594,752

 

4,347,206

 

 

 

 

 

 

 

OPERATING (LOSS) INCOME

 

(17,625

)

354,481

 

 

 

 

 

 

 

OTHER (EXPENSE) INCOME

 

 

 

 

 

Interest expense

 

(1,641,245

)

(13,851,122

)

Derivative gains

 

334,845

 

8,080,387

 

Gain on extinguishment of debt

 

 

14,430

 

Amortization of deferred income from sale of assets

 

50,613

 

50,613

 

Interest income

 

6,879

 

7,113

 

Total

 

(1,248,908

)

(5,698,579

)

 

 

 

 

 

 

NET LOSS

 

$

(1,266,533

)

$

(5,344,098

)

 

 

 

 

 

 

NET LOSS PER COMMON SHARE –

 

 

 

 

 

BASIC

 

$

(0.01

)

$

(0.05

)

DILUTED

 

$

(0.01

)

$

(0.05

)

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

5



Table of Contents

 

GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

Nine Months Ended
September 30,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

Gas

 

$

12,259,029

 

$

13,390,284

 

Oil

 

2,342,674

 

2,041,887

 

Gathering

 

 

595,942

 

Total

 

14,601,703

 

16,028,113

 

 

 

 

 

 

 

OPERATING EXPENSES

 

 

 

 

 

Lease operating

 

5,131,247

 

3,893,737

 

Gathering operations

 

 

375,848

 

Transportation and processing

 

2,147,660

 

1,926,146

 

Depletion, depreciation, amortization and accretion

 

2,785,964

 

2,764,814

 

Loss on sale of assets, net

 

92,020

 

34,726

 

General and administrative

 

3,097,199

 

5,142,871

 

Total

 

13,254,090

 

14,138,142

 

 

 

 

 

 

 

OPERATING INCOME

 

1,347,613

 

1,889,971

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

Interest expense

 

(5,057,015

)

(16,260,691

)

Derivative gains

 

708,081

 

11,368,447

 

Gain on extinguishment of debt

 

 

15,772,441

 

Amortization of deferred income from sale of assets

 

151,839

 

118,097

 

Interest income

 

20,641

 

29,691

 

Total

 

(4,176,454

)

11,027,985

 

 

 

 

 

 

 

NET (LOSS) INCOME

 

$

(2,828,841

)

$

12,917,956

 

 

 

 

 

 

 

NET (LOSS) INCOME PER COMMON SHARE –

 

 

 

 

 

BASIC

 

$

(0.02

)

$

0.12

 

DILUTED

 

$

(0.02

)

$

0.12

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

6



Table of Contents

 

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2011

 

2010

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net (loss) income

 

$

(2,828,841

)

$

12,917,956

 

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

 

 

 

 

 

Depletion, depreciation, amortization, accretion and impairment expense

 

2,785,964

 

2,764,814

 

Stock-based compensation

 

251,391

 

1,207,553

 

Gain on extinguishment of debt

 

 

(15,772,441

)

Change in fair value of derivative instruments

 

(281,081

)

(10,474,008

)

Amortization of debt discount, deferred expenses and other

 

2,428,654

 

13,067,159

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

930,880

 

94,813

 

Inventory

 

(89,435

)

(805,493

)

Prepaid expenses

 

90,774

 

285,299

 

Accounts payable

 

(624,478

)

(189,588

)

Revenue payable

 

676,882

 

680,098

 

Accrued interest

 

626,560

 

(141,650

)

Accrued expenses

 

(760,190

)

(170,106

)

Net cash provided by operating activities

 

3,207,080

 

3,464,406

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid for furniture, fixtures and other

 

(887

)

(16,683

)

Cash paid for acquisitions, development and exploration

 

(5,055,490

)

(5,135,129

)

Proceeds from sale of assets

 

 

24,309,000

 

Increase (decrease) in advances from joint interest owners

 

(1,062,672

)

2,064,152

 

Net cash (used in) provided by investing activities

 

(6,119,049

)

21,221,340

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Proceeds from issuance of common stock and warrants

 

10,000,000

 

 

Borrowings under line of credit

 

2,000,000

 

 

Repayment of borrowings

 

 

(29,000,000

)

Cash paid for stock offerings and debt issuance costs

 

(1,583,727

)

(2,096,894

)

Cash paid for repurchase of convertible notes

 

 

(54,400

)

Payment of deposit

 

 

(500,000

)

Net cash provided by (used in) financing activities

 

10,416,273

 

(31,651,294

)

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

7,504,304

 

(6,965,548

)

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS:

 

 

 

 

 

BEGINNING OF PERIOD

 

1,994,542

 

10,577,340

 

END OF PERIOD

 

$

9,498,846

 

$

3,611,792

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

7



Table of Contents

 

GASCO ENERGY, INC.

NOTES TO UNAUDITED CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

 

NOTE 1 — ORGANIZATION

 

Gasco Energy, Inc. (“Gasco,” the “Company,” “we,” “our” or “us”) is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. The Company’s principal business strategy is to enhance stockholder value by generating and developing high-potential exploitation resources in these areas. The Company’s principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. The Company is currently focusing its operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

 

The unaudited condensed consolidated financial statements included herein were prepared in accordance with generally accepted accounting principles in the United States (“US GAAP”) applicable to interim financial statements and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  Accordingly, they do not include all of the information and footnotes required by US GAAP for complete financial statements.  The accompanying unaudited condensed consolidated financial statements reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position of the Company for the interim periods presented.  Such financial statements conform to the presentation reflected in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 (“2010 10-K”) filed with the Securities and Exchange Commission (the “SEC”). The current interim period financial statements included herein should be read in conjunction with the financial statements and accompanying notes, including Note 2 — Significant Accounting Policies, included in the Company’s 2010 10-K.

 

The results of operations for the nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.

 

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements include Gasco and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated.

 

Oil and Gas Properties

 

The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, internal costs directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $0 and $75167 of internal costs during the three and nine months ended September 30, 2011, respectively, and $54,853 and $83,906 during the three and nine months ended September 30, 2010. Additionally, the Company capitalized stock compensation expense related to its consultants as further described in Note 8 — Stock-Based Compensation herein. Costs associated with production and general corporate activities are expensed in the period incurred. During April 2010, the Company began charging a

 

8



Table of Contents

 

marketing fee related to the sale of its natural gas production to the wells in which it is the operator and, therefore, the net income attributable to the outside working interest owners from such marketing activities of $22,017 and $88,352 was recorded as a credit to proved properties during the three and nine months ended September 30, 2011, respectively, and $40,396 and $96,633 during the three and nine months ended September 30, 2010. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to a cost center.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

 

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include: (i) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion; (ii) estimated future development costs to be incurred in developing proved reserves; and (iii) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs.  During October 2011, the Company entered into an agreement related to its Nevada acreage. The counterparty to the agreement will begin paying all delay rentals for this acreage and the Company will retain a small overriding interest on any drilling projects that may occur in the future. Because the Company has effectively relinquished control of this acreage and the value of any potential overriding interest in the future is uncertain, the Company has reclassified the value of this acreage of $660,000 from unproved properties into proved properties as of September 30, 2011. These costs were included in the ceiling test and depletion calculations during the quarter ended September 30, 2011. The costs of unproved properties of $36,394,721 as of September 30, 2011 are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment.

 

Total well costs are transferred to the depletable pool even when multiple targeted zones have not been fully evaluated. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Estimated reserve quantities are affected by changes in commodity prices and actual well performance.

 

Under the full cost method of accounting, the ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs exceed this ceiling limitation. The present value of estimated future net revenues is computed by applying the average first-day-of-the-month oil and gas price during the 12-month period ended September 30, 2011 to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.

 

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Table of Contents

 

Facilities and Equipment

 

The Company constructed two evaporation pits in the Riverbend area of Utah to be used for the disposal of produced water from the wells that Gasco operates in the area. The pits were depreciated using the straight-line method over their estimated useful life of twenty-five years. The costs of water disposal into the evaporation pits were charged to wells operated by Gasco and therefore, the net income attributable to the outside working interest owners from the evaporation pits of $106,433 was recorded as an adjustment to proved properties during the nine months ended September 30, 2010. These evaporative facilities were sold during February 2010. See Note 4 — Asset Sales herein.

 

The Company’s other oil and gas equipment is depreciated using the straight-line method over an estimated useful life of five to ten years. The rental of the equipment owned by the Company is charged to the wells that are operated by the Company and, therefore, the net income (expense) attributable to the outside working interest owners from the equipment rental was recorded as an adjustment to proved properties in the amount of $(9,502) and $(57,977) during the three and nine months ended September 30, 2011, respectively, and $(15,476) and $51,612 during the three and nine months ended September 30, 2010, respectively. See Note 4 — Asset Sales herein.

 

Commodity Derivatives

 

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The Company records all commodity derivative instruments at fair value within the accompanying unaudited condensed consolidated balance sheets. The Company’s management has decided not to use hedge accounting under the accounting guidance for its commodity derivatives and therefore, the changes in fair value are recognized currently in earnings. See Note 6 — Derivatives, herein.

 

Asset Retirement Obligation

 

The Company accounts for its future asset retirement obligations by recording the fair value of the liability during the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties, gathering system (sold in February 2010) or evaporative facilities costs (sold in February 2010) in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and gathering system using the units-of-production method and the evaporative facilities were depreciated on a straight-line basis over the life of the assets. The Company’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties and gathering system. The asset retirement liability is allocated to operating expense using a systematic and rational method.

 

The information below reconciles the value of the asset retirement obligation for the periods presented.

 

10



Table of Contents

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Balance beginning of period

 

$

1,171,209

 

$

1,070,202

 

$

1,119,561

 

$

1,260,965

 

Liabilities incurred

 

 

 

 

2,100

 

Property dispositions

 

 

 

 

(242,981

)

Accretion expense

 

26,715

 

24,400

 

78,363

 

74,518

 

Balance end of period

 

$

1,197,924

 

$

1,094,602

 

$

1,197,924

 

$

1,094,602

 

 

Off Balance Sheet Arrangements

 

From time to time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of September 30, 2011, the off-balance sheet arrangements and transactions that the Company had entered into included undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

 

Computation of Net Income (Loss) Per Share

 

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted-average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income per share of common stock includes both the vested and unvested shares of restricted stock. Diluted net income or loss per common share of stock is computed by dividing adjusted net income by the diluted weighted-average common shares outstanding.  Potentially dilutive securities for the diluted earnings per share calculation consist of (i) unvested shares of restricted common stock, (ii) in-the-money outstanding options and warrants to purchase shares of common stock, (iii) outstanding Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of common stock, (iv) the Company’s outstanding 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”), which are convertible into shares of Preferred Stock and common stock, and (v) the Company’s 5.5% Convertible Senior Notes due 2011 (the “2011 Notes” and together with the 2015 Notes, the “Convertible Senior Notes”), which are convertible into shares of the Company’s common stock.

 

The treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares that could have been repurchased by the Company with the proceeds from the exercise of the options (the repurchases of shares were assumed to have been made at the average market price of the common shares during the reporting period), is used to measure the dilutive impact of stock options, shares of restricted common stock, warrants and shares into which the Convertible Senior Notes and Preferred Stock are convertible.

 

Net income (loss) per share information is determined using the two-class method, which includes the weighted-average number of common shares outstanding during the period and other securities that participate in dividends (“participating security”). The Company considers the Preferred Stock to be a participating security because it includes rights to participate in dividends with the common stock. In applying the two-class method, earnings are allocated to both common stock shares and the Preferred Stock common stock equivalent

 

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shares based on their respective weighted-average shares outstanding for the period. Losses are not allocated to Preferred Stock shares. The table below sets forth the computations of basic and diluted net income (loss) per share for the three and nine months ended September 30, 2011 and 2010.

 

 

 

For the Three Months Ended
September 30,

 

For the Nine Months Ended
September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Basic Net Income (Loss) Per Common Share

 

 

 

 

 

 

 

 

 

Numerator:

 

 

 

 

 

 

 

 

 

Basic net income (loss)

 

$

(1,266,533

)

$

(5,344,098

)

$

(2,828,841

)

$

12,917,956

 

Net earnings allocated to participating securities

 

 

 

 

 

Net income (loss) attributed to common stockholders

 

$

(1,266,533

)

$

(5,344,098

)

$

(2,828,841

)

$

12,917,956

 

Denominator:

 

 

 

 

 

 

 

 

 

Weighted-average common shares outstanding

 

155,119,848

 

107,606,525

 

139,380,515

 

107,615,804

 

 

 

 

 

 

 

 

 

 

 

Basic net income (loss) per share

 

$

(0.01

)

$

(0.05

)

$

(0.02

)

$

0.12

 

 

 

 

For the Three Months Ended
September 30,

 

For the Nine Months Ended
September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Diluted Net Income (Loss) Per Common Share

 

 

 

 

 

 

 

 

 

Numerator:

 

 

 

 

 

 

 

 

 

Basic net income (loss)

 

$

(1,266,533

)

$

(5,344,098

)

$

(2,828,841

)

$

12,917,956

 

Net earnings allocated to participating securities

 

 

 

 

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

Add: interest on convertible senior notes

 

 

 

 

2,644,275

 

Diluted net income (loss) attributed to common stockholders

 

$

(1,266,533

)

$

(5,344,098

)

$

(2,828,841

)

$

15,562,231

 

Denominator:

 

 

 

 

 

 

 

 

 

Basic weighted-average common shares outstanding

 

155,119,848

 

107,606,525

 

139,380,515

 

107,615,804

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

Unvested restricted stock

 

 

 

 

 

Options to purchase common stock

 

 

 

 

 

Shares issuable upon conversion of Convertible Senior Notes

 

 

 

 

20,461,228

 

Diluted weighted-average common shares outstanding

 

155,119,848

 

107,606,525

 

139,380,515

 

128,077,032

 

 

 

 

 

 

 

 

 

 

 

Diluted net income (loss) per share

 

$

(0.01

)

$

(0.05

)

$

(0.02

)

$

0.12

 

 

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Table of Contents

 

The following shares were excluded from the computation of diluted earnings (loss) per common share as they did not have a dilutive effect.

 

 

 

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Shares related to:

 

 

 

 

 

 

 

 

 

Convertible Senior Notes

 

75,380,000

 

75,380,000

 

75,380,000

 

 

Preferred stock

 

31,833,340

 

50,959,010

 

31,833,340

 

50,959,010

 

Common stock options

 

10,233,999

 

12,189,733

 

10,233,999

 

12,189,733

 

Warrants

 

30,250,000

 

 

30,250,000

 

 

Unvested restricted stock

 

234,000

 

87,600

 

234,000

 

87,600

 

 

Use of Estimates

 

The preparation of the financial statements for the Company in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

 

The Company’s financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties, timing and costs associated with its retirement obligations, estimates of the fair value of derivative instruments, estimates used in stock-based compensation calculations and impairments to unproved property and to proved oil and gas properties.

 

Reclassifications

 

Certain reclassifications have been made to prior years’ amounts to conform to the classifications used in the current year. Such reclassifications had no effect on the Company’s net income (loss) for the periods presented.

 

Recently Issued Accounting Pronouncements

 

Effective January 1, 2011, the Company adopted ASC guidance that requires enhanced disclosure detail in the Level 3 reconciliation for fair value measurements. The adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows. Refer to Note 10 — Fair Value Measurement herein for further details regarding the Company’s assets and liabilities measured at fair value.

 

NOTE 3 — STOCK OFFERINGS

 

On June 15, 2011, the Company closed its public offering of 25,000,000 units (the “June Offering”) at a price of $0.24 per unit, for gross proceeds of $6.0 million. Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.75 of a share of common stock (the “June Warrants”). The shares of common stock and June Warrants were issued separately. The net proceeds from the June Offering were $5,108,143 , after deducting the underwriting discounts, commissions and other offering expenses of $891,857.

 

On August 3, 2011, the Company closed an underwritten registered offering of 16,000,000 units (the “August Offering” and collectively with the June Offering, the “Offerings”) at a price of $0.25 per unit, for gross proceeds of $4.0 million.  Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.71875 of a share of common stock (the “August Warrants” and collectively with the June Warrants, the “Warrants”).  The shares of common stock and August Warrants were issued separately. The net proceeds

 

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Table of Contents

 

from the August Offering were $3,623,130, after deducting underwriting discounts, commissions and other offering expenses of $376,870.

 

The Warrants are exercisable immediately for a term of sixty months, beginning at issuance, at an initial exercise price of $0.35 per share, however, the exercise price and number of shares of common stock issuable on exercise of the Warrants are subject to adjustment in the event of any stock split, reverse stock split, stock dividend, recapitalization, reorganization or similar transaction.  If the Company makes a distribution of its assets to all of its stockholders, holders of the Warrants may be entitled to participate. In the event of a Fundamental Transaction (as defined in the Warrants), at the election of a holder of a Warrant, the Company may be required to purchase the holder’s Warrant for cash in an amount equal to the value of the remaining unexercised portion of the Warrant.  As a result, the Warrants are accounted for as a liability on the Company’s consolidated balance sheet with changes in their fair value reported in earnings. Subject to certain exceptions, if the average of the daily volume weighted-average price of a share of common stock for some period of time equals or exceeds 200% of the initial exercise price of the Warrants, and if at the time of such measurement the Equity Conditions (as defined in the Warrants) are satisfied, then the Company may, subject to certain conditions, require the holders of the Warrants to exercise.

 

The Company intends to use the net proceeds from both of these Offerings for capital expenditures, working capital, acquisitions of oil and natural gas properties, repayment of indebtedness or general corporate purposes.

 

NOTE 4 — ASSET SALES

 

On February 26, 2010, the Company completed the sale (the “Closing”) of materially all of the assets (the “Asset Sale”) comprising its gathering system and its evaporative facilities, located in Uintah County, Utah, to Monarch Natural Gas, LLC (“Monarch”) pursuant to an Asset Purchase Agreement dated January 29, 2010 (the “Purchase Agreement”). The Purchase Agreement was subject to customary post-closing terms and conditions for transactions of this size and nature. At Closing, the Company received total cash consideration of $23.0 million from Monarch, the entirety of which was used to repay amounts outstanding under its Credit Facility.

 

Pursuant to the Purchase Agreement and simultaneous with Closing, Gasco entered into the following contracts with Monarch: (i) a transition services agreement pursuant to which the Company agreed to provide certain services relating to the operation of the acquired assets to Monarch for a six-month term commencing at Closing; (ii) a gas gathering agreement pursuant to which the Company agreed to dedicate its natural gas production from all of its Utah acreage for a minimum fifteen-year period and Monarch agreed to provide gathering, compression and processing services to the Company utilizing the gathering system; and (iii) a salt water disposal services agreement pursuant to which Monarch agreed that the Company may deliver salt water produced by its operations to the evaporative facilities for a minimum fifteen-year period.

 

The Company recorded deferred income of approximately $3.0 million on the Asset Sale which will be amortized over the fifteen-year terms of the gas gathering agreement and salt water disposal services agreement.

 

The following unaudited pro forma information is presented as if the Asset Sale had an effective date of January 1, 2010. The pro forma and the actual results for the three months ended September 30, 2010 were the same.

 

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Table of Contents

 

 

 

Nine Months
Ended
September 30,

 

 

 

2010

 

 

 

 

 

Revenue as reported

 

$

16,028,113

 

Less: revenue from the Asset Sale

 

595,942

 

Pro forma revenue

 

$

16,624,055

 

 

 

 

 

Net income as reported

 

$

12,917,956

 

Less: operating loss resulting from the Asset Sale

 

(824,337

)

Pro forma net income

 

$

12,093,619

 

 

 

 

 

Net income per share — basic as reported

 

$

0.12

 

Less net (loss) income per share - from the Asset Sale

 

(0.01

)

Pro forma net income per share — basic

 

$

0.11

 

 

 

 

 

Net income per share — diluted as reported

 

$

0.12

 

Less net (loss) income per share - from the Asset Sale

 

(0.01

)

Pro forma net income per share — diluted

 

$

0.11

 

 

NOTE 5 - CONVERTIBLE SENIOR NOTES

 

As of September 30, 2011, the Company had $400,000 aggregate principal amount of 2011 Notes and $45,168,000 aggregate principal amount of 2015 Notes outstanding.

 

2011 Notes

 

The 2011 Notes were governed by an indenture, dated as of October 20, 2004, by and between the Company and Wells Fargo Bank, National Association, as trustee. The 2011 Notes, which bore interest at a rate of 5.50% per annum, were issued on October 20, 2004 with a maturity date of October 5, 2011, and were repaid in full as of this date.

 

2015 Notes

 

The 2015 Notes are governed by an indenture, dated as of June 25, 2010, by and between the Company and Wells Fargo Bank, National Association, as trustee (the “2015 Indenture”). The 2015 Notes were issued on June 25, 2010 (the “Issue Date”) pursuant to the exemption from the registration requirements of the Securities Act of 1933 (the “Securities Act”), provided by Section 4(2) and Regulation D thereunder. The 2015 Notes have a maturity date of October 5, 2015.

 

The 2015 Notes bear interest at a rate of 5.50% per annum, and such interest is payable in cash semi-annually in arrears on April 5th and October 5th of each year.

 

The 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into shares of common stock or, at the election of such holder, into Preferred Stock. The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The

 

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Table of Contents

 

conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the 2015 Indenture, a holder may not convert all or any portion of such holder’s 2015 Notes into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion, beneficially own more than 4.99% of the outstanding shares of common stock (the “Maximum Ownership Percentage”), provided that such holder, upon not less than 61 days’ prior written notice to the Company, may increase the Maximum Ownership Percentage applicable to such holder (but, for the avoidance of doubt, not for any subsequent or other holder) to 9.9% of the outstanding shares of common stock.

 

The Company may redeem the 2015 Notes in whole or in part for cash at any time at a redemption price equal to 100% of the principal amount of the 2015 Notes plus any accrued and unpaid interest and liquidated damages, if any, on the 2015 Notes redeemed to but not including the redemption date, if the closing price of the Company’s common stock equals or exceeds 150% of the conversion price for at least 20 trading days within the consecutive 30 trading day period ending on the trading day before the redemption date and all of the Equity Conditions are satisfied (or waived in writing by the holders of a majority in aggregate principal amount of the 2015 Notes then outstanding). If a holder elects to convert its 2015 Notes in connection with such a provisional redemption by the Company, the Company will make an additional payment equal to the total value of the aggregate amount of the interest otherwise payable on the 2015 Notes to be calculated from the last day through which interest was paid on the 2015 Notes through and including the third anniversary of the Issue Date and discounted to the present value of such payment; provided, however, that at the Company’s option, in lieu of such discounted cash payment, the Company may deliver shares of Preferred Stock having a value equal to such discounted cash payment. The value of each share of Preferred Stock to be delivered shall be deemed equal to the product of (i) the average closing price per share of common stock over the ten trading day period ending on the trading day before the redemption date, and (ii) the number of whole shares of common stock into which each share of Preferred Stock is then convertible (without giving effect to any limitations on conversion in the Certificate of Designations of the Preferred Stock) (subject to certain conditions).

 

Upon a change of control (as defined in the 2015 Indenture), each holder of 2015 Notes may require the Company to repurchase some or all of its 2015 Notes at a repurchase price equal to 100% of the aggregate principal amount of the 2015 Notes to be repurchased plus accrued and unpaid interest and liquidated damages, if any, to but not including the date of purchase, plus, in certain circumstances, a make whole premium. The Company may pay the change of control purchase price and/or the make whole premium in cash or shares of Preferred Stock at the Company’s option. In addition, in the case of the make whole premium, at the Company’s option, the Company may pay such premium in the same form of consideration used to pay for the shares of common stock in connection with the transaction constituting the change of control.

 

The 2015 Indenture contains usual and customary covenants limiting the Company’s ability to incur additional indebtedness, with certain exceptions, or liens on its property or assets, restricting its ability to make dividends or other distributions, requiring its domestic subsidiaries to guaranty the 2015 Notes, requiring it to list the shares of common stock that may be issued upon conversion of the 2015 Notes and the Preferred Stock on the NYSE Amex or any other U.S. national or regional securities exchange on which the common stock is then listed, and requiring it to use reasonable best efforts to obtain stockholder approval for the issuance of shares of common stock upon conversion of the 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes.

 

The 2015 Notes are unsecured and unsubordinated and rank on a parity in right of payment with all of the Company’s existing and future senior unsecured indebtedness, rank senior in right of payment to any of the Company’s existing and future subordinated indebtedness, and are effectively subordinated in right of payment to any of the Company’s secured indebtedness or other obligations to the extent of the value of the assets

 

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Table of Contents

 

securing such indebtedness or other obligations. The Company’s subsidiaries guarantee the 2015 Notes pursuant to a Guaranty Agreement dated as of June 25, 2010, by and among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of the Trustee.

 

The debt discount that was recognized in connection with the 2015 Notes is being accreted to interest expense under the effective interest method at a rate of 26.3%.

 

NOTE 6 — DERIVATIVES

 

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. As of September 30, 2011, natural gas derivative instruments consisted of one swap agreement for natural gas production through December 31, 2011 and one collar agreement for production from January 1, 2012 through December 31, 2012. As of December 31, 2010, natural gas derivative instruments consisted of two swap agreements for gas production through March 2011. These natural gas derivative instruments allow the Company to predict with greater certainty the effective natural gas prices to be realized for its production. The Company’s derivative contracts are described below:

 

·                  For its swap instrument, the Company receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

 

·                  The Company’s costless collar contains a fixed floor price (put) and ceiling price (call). The Company receives the difference between the published index price and the floor price if the index price is below the floor price. The Company pays the difference between the ceiling price and the index price only if the index price is above the ceiling price. If the index price is between the ceiling and the floor prices, no amounts are paid or received.

 

On June 15, 2011, the Company issued the June Warrants to purchase 18,750,000 shares of common stock and on August 3, 2011, the Company issued the August Warrants to purchase 11,500,000 shares of common stock. The Warrants have an initial exercise price of $0.35 per share (subject to adjustment) and sixty-month term, as further described in Note 3 — Stock Offerings, herein. The Warrants contain a contingent cash settlement provision at the option of the holder and accordingly, are classified as a derivative liability and are subject to the classification and measurement standards for derivative financial instruments.

 

Prior to September 15, 2010, the date on which the Company received shareholder approval for the issuance of the shares of common stock to settle the conversion of the 2015 Notes, the conversion feature in the 2015 Notes was accounted for separately as an embedded derivative at fair value, yet presented together with the 2015 Notes, in the consolidated balance sheet.  The changes in the fair value of the embedded derivative through September 15, 2010 were reported as derivative gains (losses) in the consolidated statement of operations.

 

The following table details the fair value of the derivatives recorded in the consolidated balance sheets:

 

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Table of Contents

 

 

 

Location on
Consolidated

 

Fair Value at

 

 

 

Balance Sheets

 

September 30, 2011

 

December 31, 2010

 

 

 

 

 

 

 

 

 

Natural gas derivative contracts

 

Current assets

 

$

318,143

 

$

193,959

 

Natural gas derivative contracts

 

Noncurrent assets

 

53,772

 

 

Warrant derivative

 

Noncurrent liabilities

 

3,932,500

 

 

 

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and nine months ended September 30, 2011 and 2010.

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Realized gains on commodity instruments

 

$

17,380

 

$

645,956

 

$

427,000

 

$

894,439

 

Change in fair value of commodity instruments

 

377,465

 

594,039

 

177,956

 

3,633,616

 

Change in fair value of warrant derivative

 

(60,000

)

 

103,125

 

 

Change is fair value of embedded derivative feature

 

 

6,840,392

 

 

6,840,392

 

 

 

 

 

 

 

 

 

 

 

Total realized and unrealized gains (losses) recorded

 

$

334,845

 

$

8,080,387

 

$

708,081

 

$

11,368,447

 

 

These realized and unrealized gains and losses are recorded in the accompanying consolidated statements of operations as derivative gains and losses.

 

The Company’s swap agreement as of September 30, 2011 is summarized in the table below:

 

Agreement
Type

 

Remaining
Term

 

Quantity

 

Fixed Price
Counterparty
payer

 

Floating Price (a)
Gasco payer

Swap

 

10/11 — 12/11

 

2,000 MMBtu/day

 

$4.00/MMBtu

 

NW Rockies

 


(a)          Northwest Pipeline Rocky Mountains — Inside FERC first-of-month index price.

 

The Company’s costless collar agreement as of September 30, 2011 is summarized in the table below:

 

Agreement
Type

 

Remaining
Term

 

Quantity

 

Index
Price (a)

 

Call Price
Counterparty
buyer

 

Put Price
Gasco buyer

Costless collar

 

1/12 — 12/12

 

2,000 MMBtu/day

 

NW Rockies

 

$4.25/MMBtu

 

$5.12/MMBtu

 


(a)                                  Northwest Pipeline Rocky Mountains — Inside FERC first-of-month index price.

 

18



Table of Contents

 

NOTE 7 — GAS PROCESSING AGREEMENT

 

On September 21, 2011, the Company entered into a Gas Processing Agreement (the “Chipeta Processing Agreement”) with Chipeta Processing LLC (“Chipeta”) pursuant to which the Company dedicated certain of its natural gas production from its acreage in Utah to Chipeta for processing, and Chipeta agreed to process all natural gas production from such assets through facilities and related equipment that Chipeta owns or will construct on or before December 31, 2012.

 

The primary term of the Chipeta Processing Agreement is ten years, beginning after the in-service date of a 300 MMcf/d cryogenic processing facility to be built by Chipeta. The primary term will be extended for one year terms unless terminated by either party giving 180 days’ notice prior to the expiration of the then-current term.  If by December 31, 2012, among other conditions, (i) Chipeta has not completed its construction obligation and (ii) Questar Pipeline Company has not completed and received necessary regulatory approvals for the conversion of certain of its pipelines and facilities from a dry line to a wet line, the obligations of the Company and Chipeta under the Chipeta Processing Agreement shall be void.

 

Pursuant to the Chipeta Processing Agreement, the Company reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing.  The Company agreed to pay specified processing fees per MMBtu as well as a pro rata share of all applicable electric compression costs, subject to escalation on an annual basis.  The Company may also be required to make periodic deficiency payments to Chipeta for any shortfalls from the specified minimum volume commitments.

 

Historically, the Company’s natural gas production has been gathered and processed by Monarch pursuant to the Gas Gathering and Processing Agreement effective March 1, 2010 between Monarch and the Company (the “Monarch Processing Agreement”).  In connection with the Chipeta Processing Agreement, on September 20, 2011, the Company entered into a Letter Agreement to Amend the Monarch Processing Agreement (the “Monarch Amendment”).

 

Pursuant to the Monarch Amendment, Monarch agreed to temporarily release and waive its rights under the Monarch Processing Agreement to process the first 30,000 MMBtu/d of volume from certain of the Company’s natural gas production.  Monarch will retain processing rights for natural gas volumes in excess of the initial 30,000 MMBtu/d of production, unless otherwise agreed.  In addition to any processing fees paid by the Company to Monarch for the natural gas processed by Monarch, the Company agreed to pay Monarch a process sharing fee calculated based upon payment received from Chipeta for the sale of product extracted from the Company’s natural gas processed pursuant to the Chipeta Processing Agreement described above.  Monarch will continue to gather the Company’s natural gas, including such natural gas to be processed by Chipeta pursuant to the Chipeta Processing Agreement. The initial term and effective date of the Monarch Amendment will coincide with the term and effective date of the Chipeta Processing Agreement.

 

NOTE 8 — STOCK-BASED COMPENSATION

 

The Company has outstanding common stock options and restricted stock issued under its equity incentive plans. The Company measures the fair value at the grant date for stock option grants and restricted stock awards and records compensation expense over the requisite service period. The expense recognized over the service period includes an estimate of the awards that will be forfeited.  The Company assumes no forfeitures for employee awards based on the Company’s historical forfeiture experience. The fair value of stock options is calculated using the Black-Scholes option-pricing model and the fair value of restricted stock is based on the fair value of the stock on the date of grant.

 

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The Company accounts for stock compensation arrangements with non-employees using a fair value approach. Under this approach, the stock compensation related to the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair value on that date. During the three and nine months ended September 30, 2011 and 2010, the Company recognized stock-based compensation as follows:

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Employee compensation

 

$

75,346

 

$

333,111

 

$

252,244

 

$

1,211,511

 

Consultant compensation (reduction in compensation)

 

(265

)

(761

)

(1,705

)

(5,687

)

Total stock-based compensation

 

75,081

 

332,350

 

250,539

 

1,205,824

 

Less: consultant compensation expense (reduction in expense) capitalized as proved property

 

(132

)

(359

)

(852

)

(1,729

)

Stock-based compensation expense

 

$

75,213

 

$

332,709

 

$

251,391

 

$

1,207,553

 

 

Stock Options

 

The following table summarizes the stock option activity in the equity incentive plans from January 1, 2011 through September 30, 2011:

 

 

 

Shares Underlying
Stock Options

 

Weighted-Average
Exercise Price

 

Outstanding at January 1, 2011

 

12,689,733

 

$

1.63

 

Granted

 

151,000

 

$

0.25

 

Exercised

 

 

 

Forfeited

 

(198,114

)

$

0.98

 

Cancelled

 

(2,408,620

)

$

1.53

 

Outstanding at September 30, 2011

 

10,233,999

 

$

1.64

 

Exercisable at September 30, 2011

 

9,362,122

 

$

1.75

 

 

During the year ended December 31, 2010, the Company granted 1,371,000 options to purchase 50,000, 175,000, 646,000 and 500,000 shares of common stock with exercise prices of $0.34, $0.35, $0.36 and $0.37 per share, respectively. These options have a one- or two-year vesting period and expire within five years of the grant date. These options were granted contingent on stockholder approval of a new stock option plan, which was approved at the Company’s annual meeting of stockholders during July 2011. Therefore these options were accounted for as liability awards until stockholder approval was obtained, at which time they were accounted for as equity awards.

 

During the third quarter of 2011, the Company granted 151,000 options to purchase common stock with an exercise price of $0.25. These options vest in equal portions over the following two-year period and expire within five years of the grant date.

 

The following table summarizes information related to the outstanding and vested options as of September 30, 2011:

 

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Outstanding Options

 

Vested Options

 

Number of shares

 

10,233,999

 

9,362,122

 

Weighted-Average Remaining Contractual Life

 

2.74 years

 

2.60 years

 

Weighted-Average Exercise Price

 

$

1.64

 

$

1.75

 

Aggregate intrinsic value

 

 

 

 

The aggregate intrinsic value in the table above represents the total pretax intrinsic value. As of September 30, 2011, the fair value of the Company’s stock of $0.19 does not exceed the exercise price of the outstanding options.

 

The Company settles employee stock option exercises with newly issued common shares.

 

As of September 30, 2011, there is $161,152 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 1.8 years.

 

Restricted Stock

 

The following table summarizes the restricted stock activity from January 1, 2011 through September 30, 2011:

 

 

 

Restricted
Stock

 

Weighted-Average
Grant Date
Fair Value

 

Outstanding at January 1, 2011

 

191,300

 

$

0.70

 

Granted

 

75,000

 

$

0.25

 

Vested

 

(19,400

)

$

2.37

 

Forfeited

 

(12,900

)

$

1.79

 

Outstanding at September 30, 2011

 

234,000

 

$

0.36

 

 

As of September 30, 2011, there is $79,639 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a period of 2.9 years.

 

Effective October 1, 2011, the Company’s non-employee directors agreed to reduce their monthly compensation and in exchange, on October 5, 2011, the Company granted stock appreciation rights (the “Stock Appreciation Rights”) related to a total of 500,000 shares of the Company’s common stock to these directors. The Stock Appreciation Rights provide the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) the fair market value of one share of common stock on the date of exercise, over (ii) $0.25, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised (“Appreciation Amount”). The Stock Appreciation Rights vest on January 31, 2012 or earlier under certain circumstances as described in the Stock Appreciation Right Agreement, which has been filed as an exhibit hereto. The Stock Appreciation Rights that vest on January 31, 2012 will be automatically exercised on February 1, 2012 and will be settled by the Company through payment of the Appreciation Amount in a lump sum cash payment within a period of 10 business days.

 

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NOTE 9 — CREDIT FACILITY

 

The Company’s $250 million revolving credit facility (“Credit Facility”) is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. As a result of the completion of the semi-annual redeterminations of the Company’s borrowing base under the Credit Facility, the borrowing base was decreased from $16 million to $15 million in May 2011, and was further decreased to $13 million effective November 1, 2011. As of September 30, 2011, there were loans in the amount of $8,544,969 and letters of credit in the amount of $25,195 outstanding under the Credit Facility. As of November 1, 2011, the unused borrowing base is approximately $4.4 million.

 

Borrowings made under the Credit Facility are secured by a pledge of the capital stock of certain of the Company’s subsidiaries and mortgages on substantially all of the Company’s oil and gas properties. Interest on borrowings is payable monthly and principal is due at maturity on March 26, 2012. The Company does not expect that the maturity date of its Credit Facility will be extended. Management is discussing alternative borrowing arrangements with other lenders and while the Company currently believes that it will be able to find a replacement lender, there can be no assurance that it will be able to obtain adequate alternative financing on acceptable terms or at all. If the Company was to secure an alternative borrowing arrangement, it expects that such arrangement will include less favorable terms, including with respect to the cost of borrowing and financial covenants, than those of its current Credit Facility.  If the Company is unable to secure an alternative borrowing arrangement but is able to repay any amounts understanding under the Credit Facility at maturity with cash on hand, it will nevertheless lose a primary source of liquidity and be required to fund its business and operations going forward without outside capital.  There is no guarantee that the Company will be able to do so, in which case it may have to significantly reduce its spending and may be unable to execute its existing short-term or long-term business plan and its liquidity and results of operations may be materially adversely affected.

 

Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate (“ABR”). The Eurodollar rate is calculated as LIBOR plus an applicable margin that, as amended, varies from 2.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 3.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The ABR, as amended, is equal to the sum of (i) the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50% and (c) the Adjusted LIBOR for a one-month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The Company elects the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require the Company to use the non-elected basis in the event that the elected basis does not adequately and fairly reflect the cost of making such loans. The interest rate on borrowings outstanding under our Credit Facility is 5.1% as of September 30, 2011.

 

The Credit Facility requires the Company to comply with financial covenants that require it to maintain (1) a current ratio (defined as current assets plus unused availability under the Credit Facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1.0; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Facility) for the most recent four quarters not to be greater than 3.5:1.0 for each fiscal quarter.  In addition, the Credit Facility contains covenants that restrict the Company’s ability to incur other indebtedness, create liens or sell the Company’s assets, pay dividends on the Company’s common stock and make certain investments. Sustained or lower oil and natural gas prices could reduce the Company’s consolidated EBITDAX and thus could reduce the Company’s ability to maintain existing levels of bank debt or incur additional indebtedness. Any failure to be in compliance with any material provision or covenant of the Credit Facility could result in a

 

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default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under the Credit Facility.  Additionally, should the Company’s obligation to repay indebtedness under the Credit Facility be accelerated, the Company would be in default under the indenture governing the 2015 Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such 2015 Notes.  To the extent it becomes necessary to address any anticipated covenant compliance issues, the Company will seek to obtain a waiver or amendment of the Credit Facility from the Lenders, and in the event that such waiver or amendment is not granted, the Company may be required to sell a portion of its assets or issue additional securities, which would be dilutive to the Company’s stockholders.  Any sale of assets or issuance of additional securities may not be on terms acceptable to the Company.

 

As of September 30, 2011, the Company’s current ratio is 3.5:1.0 and its senior debt to EBITDAX ratio is 1.6:1.0, and the Company is in compliance with each of the covenants contained in the Credit Facility.

 

NOTE 10 — FAIR VALUE MEASUREMENTS

 

The authoritative guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

 

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

 

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or

 

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flows models or valuations.

 

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below in all periods presented.

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010 by level within the fair value hierarchy:

 

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Fair Value Measurements Using

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

September 30, 2011

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

317,915

 

$

 

$

371,915

 

Liabilities:

 

 

 

 

 

 

 

 

 

Warrant derivatives

 

$

 

$

 

$

3,932,500

 

$

3,932,500

 

 

 

 

 

 

 

 

 

 

 

December 31, 2010

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

193,959

 

$

 

$

193,959

 

 

As of September 30, 2011, the Company’s commodity derivative financial instruments are comprised of one natural gas swap agreement and one costless collar agreement. The fair values of the swap and collar agreements are determined based primarily on inputs that are derived from observable data at commonly quoted intervals for the full term of the derivatives and are, therefore, considered Level 2 in the fair value hierarchy. The Company determines the fair value of these contracts under the income valuation technique using a discounted cash flow model for the swap and option pricing model for the collar. The valuation models require a variety of inputs, including contractual terms, projected gas market prices, discount rate and credit risk adjustments, as appropriate. The Company has consistently applied this valuation technique in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds. The counterparty in all of the Company’s commodity derivative financial instruments is the Administrative Agent under the Credit Agreement. See Note 9 — Credit Facility herein.

 

As of September 30, 2011, the Company’s warrant derivative financial instrument is comprised of the Warrants issued by the Company to purchase 30,250,000 shares of common stock, as further described in Note 3 — Stock Offerings, herein. The Warrants are valued using a binomial lattice-based valuation model and are classified as Level 3 in the fair value hierarchy. The lattice-based valuation technique is utilized because it embodies all of the requisite assumptions (including the underlying price, exercise price, term, volatility, and risk-free interest-rate) that are necessary to measure the fair value of these instruments. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based techniques are highly volatile and sensitive to changes in the trading price of the Company’s common stock, which has a high-historical volatility.

 

A summary of the Warrants issued by the Company is as follows:

 

 

 

Number of
Warrants

 

Exercise
Price

 

Weighted
Average
Remaining
Contractual Life

 

Warrants outstanding as of 12/31/10

 

 

 

 

Warrants issued

 

30,250,000

 

$

0.35

 

60 months

 

Warrants outstanding as of 9/30/11

 

30,250,000

 

$

0.35

 

57.2 months

 

 

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The significant assumptions used in the valuation of the warrant derivative liability are as follows:

 

Exercise price

 

$0.35 per share

Volatility

 

103%

Term of Warrants

 

60 months

Risk-free interest rate

 

1% - 2%

 

The following table sets forth a reconciliation of changes in the fair value of financial liabilities classified as Level 3 in the fair value hierarchy:

 

 

 

Warrant
Derivative

 

Balance as of January 1, 2011

 

$

 

Total gains (realized or unrealized):

 

 

 

Included in earnings

 

103,125

 

Included in other comprehensive income

 

 

Issuances

 

(4,035,625

)

Settlements

 

 

Transfers in and out of Level 3

 

 

Balance as of September 30, 2011

 

$

(3,932,500

)

 

 

 

 

Change in unrealized gains included in earnings relating to instruments still held as of September 30, 2011

 

$

103,125

 

 

The carrying amounts of cash and cash equivalents, accounts receivable, note receivable, accounts payable, accrued liabilities, 2011 Notes and long-term debt approximate fair values because of the short-term maturities and or liquid nature of these assets and liabilities. The carrying amount of the Company’s note receivable approximates fair value based on current interest rates for similar instruments. The estimated fair value of the 2015 Notes of $29,055,000 and $31,766,000 as of September 30, 2011 and December 31, 2010, respectively, was determined using a discounted cash flow and option pricing model.

 

NOTE 11 - STATEMENTS OF CASH FLOWS

 

During the nine months ended September 30, 2011, the Company’s non-cash investing and financing activities consisted of the following transactions:

 

·                  Reduction in stock-based compensation expense of $852 capitalized as proved property.

 

·      Conversion of 34,600 shares of Preferred Stock into 5,766,667 shares of common stock.

 

·                  Additions to oil and gas properties included in accounts payable of $548,322.

 

During the nine months ended September 30, 2010, the Company’s non-cash investing and financing activities consisted of the following transactions:

 

·                  Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $2,100.

 

·                  Reduction in stock-based compensation expense of $1,729 capitalized as proved property.

 

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·                  Additions to oil and gas properties included in accounts payable of $236,261.

 

·                  Recognition of deferred income of $3,036,791 in connection with the Asset Sale described in Note 4 —Asset Sales, herein.

 

·                  Exchange of 2011 Notes for 2015 Notes of $64,532,000.

 

·                  Exchange of $19,364,000 of the principal value of 2015 Notes into 305,754 shares of Preferred Stock and debt derivative liabilities of $15,358,616 reclassified to Additional Paid-In-Capital.

 

Cash paid for interest during the nine months ended September 30, 2011 and 2010 was $1,967,483 and $3,231,004, respectively. There was no cash paid for income taxes during the nine months ended September 30, 2011 and 2010.

 

NOTE 12 — LEGAL PROCEEDINGS

 

The Company is party to various legal proceedings arising out of the normal course of business.  The two most significant legal proceedings to which the Company is subject are summarized below.  The ultimate outcome of the Clean Water Act Compliance Order matter cannot presently be determined, nor can the liability that could potentially result from an adverse outcome be reasonably estimated at this time.  The Company does not expect the outcome of this proceeding or of the EPA Enforcement Action to have a material adverse effect on its financial position, results of operations or cash flows.

 

Clean Water Act Compliance Order Matter

 

On October 3, 2011, the Company received a compliance order from the United States Environmental Protection Agency (“EPA”) Region 8 under the authority of the federal Clean Water Act.  The compliance order alleges that the Company violated the Clean Water Act by discharging fill material into wetlands adjacent to the Green River in Utah without authorization on two occasions: once when it constructed an access road to a future well location in either 2004 or 2005 and once when it constructed an access road and a well pad in 2007 or 2008.  The compliance order directs the Company to remove all dredged or fill material alleged to have been placed in the wetlands and to restore the wetlands to their pre-impact condition and grade, which would require that the Company plug and abandon the well alleged to have been installed in a wetlands area.  The compliance order does not seek any civil penalties for the alleged violations.  The Company disagrees with some of the factual contentions in the compliance order, and is evaluating its options, which may include challenging the compliance order in federal court, although whether such compliance orders may be appealed at this stage of the administrative process is a contested issue that is currently before the United States Supreme Court.  The Company is not able to predict the outcome of this matter at this time.

 

EPA Enforcement Action

 

On June 22, 2007, Riverbend Gas Gathering, LLC (“Riverbend”) voluntarily notified the EPA Region 8 office in Denver, Colorado, of its discovery that Riverbend apparently had not obtained certain air permits or complied with certain air pollution regulatory programs applicable to its operations at the Riverbend Compressor Station in Uintah County, Utah.  Subsequent to this notice and negotiations on the matter, Riverbend and the EPA entered into a consent decree that was lodged in the United States District Court of the District of Utah on December 30, 2010.  The consent decree resolves the apparent violations, requires Gasco to pay a civil penalty of $350,000, which was paid on May 5, 2011, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that

 

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will authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented.  The consent decree was approved and entered by the reviewing court on April 6, 2011.

 

Under the Purchase Agreement dated January 29, 2010, by which the Company sold its gathering system and evaporative facilities located in Uintah County, Utah to Monarch, the Company retained the obligation to pay any civil penalty assessed and the capital cost of the equipment required to be installed pursuant to the consent decree, and also agreed to reimburse Monarch for certain miscellaneous expenses incurred to finalize the consent decree and obtain certain changes to the Riverbend Compressor Station’s air permits that are required by the consent decree.  Monarch is also a party to the consent decree and will be responsible for implementing most of the consent decree requirements at the Riverbend Compressor Station other than payment of the civil penalty, which has already taken place, and the installation of capital equipment.  The Company believes that all necessary pollution control and other equipment required by the consent decree is already installed at the site or accounted for in our capital budget, and that the expenses required by the consent decree will not materially affect the Company’s financial position or liquidity.

 

NOTE 13 — GUARANTOR SUBSIDIARIES

 

On August 31, 2011, Gasco filed a Form S-3 shelf registration statement with the SEC, which was declared effective on September 20, 2011. Under this registration statement, Gasco may from time to time offer and sell securities including common stock, preferred stock, depositary shares, warrants and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of its subsidiaries:  Gasco Production Company, Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (collectively, the “Guarantor Subsidiaries”). The stand-alone parent entity, Gasco Energy, Inc., has insignificant independent assets and no operations. Therefore, supplemental financial information on a condensed consolidating basis of the Guarantor Subsidiaries is not required. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the Guarantor Subsidiaries, except those imposed by applicable law.

 

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Table of Contents

 

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Overview

 

We are a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. Our principal business strategy is to enhance stockholder value by using technologies new to a specific area to generate and develop high-potential exploitation resources in these areas. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. We are currently focusing our operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

 

Recent Developments

 

Stock Offerings

 

On June 15, 2011, we closed our public offering of 25,000,000 units (the “June Offering”) at a price of $0.24 per unit, for gross proceeds of $6.0 million. Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.75 of a share of common stock (the “June Warrants”). The shares of common stock and June Warrants were issued separately. The net proceeds from the June Offering were approximately $5.1 million, after deducting the underwriting discounts, commissions and other offering expenses of approximately $892,000.

 

On August 3, 2011, we closed an underwritten registered offering of 16,000,000 units (the “August Offering” and collectively with the June Offering, the “Offerings”) at a price of $0.25 per unit, for gross proceeds of $4.0 million.  Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.71875 of a share of common stock (the “August Warrants” and collectively with the June Warrants, the “Warrants”).  The shares of common stock and August Warrants were issued separately. The net proceeds from the August Offering were approximately $3.6 million, after deducting underwriting discounts and commissions and other offering expenses of approximately $377,000.

 

The Warrants are exercisable immediately for a term of sixty months, beginning at issuance, at an initial exercise price of $0.35 per share, however, the exercise price and number of shares of common stock issuable on exercise of the Warrants are subject to adjustment in the event of any stock split, reverse stock split, stock dividend, recapitalization, reorganization or similar transaction.  If we make a distribution of our assets to all of our stockholders, holders of the Warrants may be entitled to participate. In the event of a Fundamental Transaction (as defined in the Warrants), at the election of a holder of a Warrant, we may be required to purchase the holder’s Warrant for cash in an amount equal to the value of the remaining unexercised portion of the Warrant.  Subject to certain exceptions, if the average of the daily volume weighted-average price of a share of common stock for some period of time equals or exceeds 200% of the initial exercise price of the Warrants, and if at the time of such measurement the Equity Conditions (as defined in the Warrants) are satisfied, then we may, subject to certain conditions, require the holders of the Warrants to exercise.

 

We intend to use the net proceeds from the both of these Offerings for capital expenditures, working capital, acquisitions of oil and natural gas properties, repayment of indebtedness or general corporate purposes.

 

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Clean Water Act Compliance Order Matter

 

On October 3, 2011, we received a compliance order from the United States Environmental Protection Agency (“EPA”) Region 8 under the authority of the federal Clean Water Act.  The compliance order alleges that we violated the Clean Water Act by discharging fill material into wetlands adjacent to the Green River in Utah without authorization on two occasions: once when we constructed an access road to a future well location in either 2004 or 2005 and once when we constructed an access road and a well pad in 2007 or 2008.  The compliance order directs us to remove all dredged or fill material alleged to have been placed in the wetlands and to restore the wetlands to their pre-impact condition and grade, which would require that we plug and abandon the well alleged to have been installed in a wetlands area.  The compliance order does not seek any civil penalties for the alleged violations.  We disagree with some of the factual contentions in the compliance order, and we are evaluating our options, which may include challenging the compliance order in federal court, although whether such compliance orders may be appealed at this stage of the administrative process is a contested issue that is currently before the United States Supreme Court.  We are not able to predict the outcome of this matter at this time.

 

Gas Processing Agreement

 

On September 21, 2011, we entered into a Gas Processing Agreement (the “Chipeta Processing Agreement”) with Chipeta Processing LLC (“Chipeta”) pursuant to which we dedicated certain of our natural gas production from our acreage in Utah to Chipeta for processing, and Chipeta agreed to process all natural gas production from such assets through facilities and related equipment that Chipeta owns or will construct on or before December 31, 2012.

 

The primary term of the Chipeta Processing Agreement is ten years, beginning after the in-service date of a 300 MMcf/d cryogenic processing facility to be built by Chipeta. The primary term will be extended for one year terms unless terminated by either party giving 180 days’ notice prior to the expiration of the then-current term.  If by December 31, 2012, among other conditions, (i) Chipeta has not completed its construction obligation and (ii) Questar Pipeline Company has not completed and received necessary regulatory approvals for the conversion of certain of its pipelines and facilities from a dry line to a wet line, our obligations and those of Chipeta under the Chipeta Processing Agreement shall be void.

 

Pursuant to the Chipeta Processing Agreement, we reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing.  We agreed to pay specified processing fees per MMBtu as well as a pro rata share of all applicable electric compression costs, subject to escalation on an annual basis.  We may also be required to make periodic deficiency payments to Chipeta for any shortfalls from the specified minimum volume commitments.

 

Historically, our natural gas production has been gathered and processed by Monarch pursuant to the Gas Gathering and Processing Agreement effective March 1, 2010 between Monarch and us (the “Monarch Processing Agreement”).  In connection with the Chipeta Processing Agreement, on September 20, 2011, we entered into a Letter Agreement to Amend the Monarch Processing Agreement (the “Monarch Amendment”).

 

Pursuant to the Monarch Amendment, Monarch agreed to temporarily release and waive its rights under the Monarch Processing Agreement to process the first 30,000 MMBtu/d of volume from certain of our natural gas production.  Monarch will retain processing rights for natural gas volumes in excess of the initial 30,000 MMBtu/d of production, unless otherwise agreed.  In addition to any processing fees paid by us to Monarch for the natural gas processed by Monarch, we agreed to pay Monarch a process sharing fee calculated based upon payment received from Chipeta for the sale of product extracted from our natural gas processed pursuant to the

 

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Chipeta Processing Agreement described above.  Monarch will continue to gather our natural gas, including such natural gas to be processed by Chipeta pursuant to the Chipeta Processing Agreement. The initial term and effective date of the Monarch Amendment will coincide with the term and effective date of the Chipeta Processing Agreement.

 

Green River Oil Wells

 

During the third quarter of 2011, we spudded two wells that will test the productive potential of the Green River Formation at approximately 5,500 feet proposed total vertical depth.  We operate both wells with a 100% working interest.  Drilling of these wells was commenced with a spudder rig and surface casing was set.  The timetable to finish drilling and to complete these two wells is dependent upon the drilling rig schedule and frac crew availability, although we currently plan to finish drilling and completion by the end of November 2011.

 

Completion Operations

 

As previously disclosed, we have elected to defer our uphole natural gas well recompletion program until the fourth quarter in anticipation of stronger seasonal natural gas prices.  The exact timing of the recompletions is based on frac crew availability.

 

During the first nine months of 2011, we recompleted one gross (0.3333 net) natural gas well in the Uinta Basin, Utah. As of September 30, 2011, we operated 133 gross wells and we currently have an inventory of 18 operated wells with up-hole recompletions and one Upper Mancos well awaiting initial completion activities.

 

California Projects

 

Northwest McKittrick. The operator of this shallow oil prospect continues to work with the California State Agencies to acquire the appropriate permits.  Progress has been slowed due to California state budget issues and forced furloughs affecting the regulatory agencies.  While some progress has been made, final approval is still pending from the California Fish and Game Department.

 

Willow Springs. The operator of this oil prospect has been analyzing recently acquired 3-D seismic data and is currently high-grading drillable locations based upon the ongoing 3-D interpretation. Well permitting has begun and our understanding is that the project is on schedule to have an initial well drilled by year-end 2011.

 

Antelope Valley Trend. The operator of these oil and liquids-rich prospects is in the process of shooting 3-D seismic data over the Antelope Valley prospects.  Our agreement with our operator requires that the initial earning well be spud during the first half of 2012.

 

San Joaquin Basin. We continue to develop new prospects and acquire acreage along the west side of the San Joaquin Basin.  The new prospects are a continuation of the structural and stratigraphic geologic model that we have been working on for the past nine years that has yielded recent success along the west side as demonstrated by discoveries and field development by other operators with similar geologic models.

 

Nevada Project

 

During October 2011, we entered into an agreement related to our Nevada project consisting of approximately 74,000 gross and net acres located within White Pine and Elko Counties of Nevada.  The counterparty to the agreement agreed to pay all delay rentals on this acreage and we will retain a small overriding interest on any drilling projects that may occur in the future. Because we have effectively relinquished control of this acreage

 

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and the value of any potential overriding interest in the future is uncertain, we have reclassified the value of this acreage of $660,000 from unproved properties into proved properties as of September 30, 2011.

 

Director Stock Appreciation Right Grants

 

Effective October 1, 2011, our non-employee directors agreed to reduce their monthly compensation and in exchange, on October 5, 2011, we granted stock appreciation rights (the “Stock Appreciation Rights”) related to a total of 500,000 shares of our common stock to these directors. The Stock Appreciation Rights provide the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) the fair market value of one share of common stock on the date of exercise, over (ii) $0.25, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised (“Appreciation Amount”). The Stock Appreciation Rights vest on January 31, 2012 or earlier under certain circumstances as described in the Stock Appreciation Right Agreement, which has been filed as an exhibit hereto. The Stock Appreciation Rights that vest on January 31, 2012 will be automatically exercised on February 1, 2012 and will be settled through payment of the Appreciation Amount in a lump sum cash payment within a period of 10 business days.

 

Oil and Gas Production Summary

 

The following table presents our production and price information during the three and nine months ended September 30, 2011 and 2010. The Mcfe calculations assume a conversion of six Mcf for each Bbl of oil.

 

 

 

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Natural gas production (Mcf)

 

879,788

 

1,073,831

 

2,823,630

 

3,097,448

 

Average sales price per Mcf

 

$

4.49

 

$

3.75

 

$

4.34

 

$

4.32

 

 

 

 

 

 

 

 

 

 

 

Oil production (Bbl)

 

8,424

 

11,019

 

28,902

 

32,378

 

Average sales price per Bbl

 

$

74.87

 

$

60.96

 

$

81.06

 

$

63.06

 

 

 

 

 

 

 

 

 

 

 

Production (Mcfe)

 

930,332

 

1,139,945

 

2,997,042

 

3,291,716

 

 

Our equivalent oil and gas production decreased by 18% and 9% during the three and nine months ended September 30, 2011 as compared to the three and nine months ended September 30, 2010, respectively, primarily due to a third-party gathering company’s high line pressures, unusually high compressor downtime and the normal production declines associated with the tight sand reservoirs on our existing wells.

 

Liquidity and Capital Resources

 

Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities or asset sales, availability under our Credit Facility, and access to capital markets, to the extent available. As a result of the semi-annual redeterminations of our borrowing base under the Credit Facility, our borrowing base was decreased to $15 million from the previously available $16 million in May 2011, and further decreased to $13 million effective November 1, 2011. As of November 1, 2011, we have approximately $8.6 million aggregate amount of outstanding borrowings (including $25,195 of outstanding letters of credit) thereunder. Our Credit Facility provides for periodic and special borrowing base redeterminations which could affect our available borrowing base and our lenders may further reduce our borrowing base in the future. Our

 

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inability to access additional borrowings in excess of our $4.4 million of current existing capacity under our Credit Facility may limit our ability to increase our operating budget and execute on our growth plans.

 

As of September 30, 2011, we had negative working capital of approximately $470,445 primarily due to the approximately $8.5 million aggregate amount of borrowings outstanding under our Credit Facility, which is presently classified as a current liability due March 26, 2012, and the $400,000 current liability related to the 2011 Notes that was paid in October 2011. We do not expect that the maturity date of our Credit Facility will be extended. We are discussing alternative borrowing arrangements with other lenders and while we currently believe that we will be able to find a replacement lender, there can be no assurance that we will be able to obtain adequate alternative financing on acceptable terms or at all.  For example, our recent results of operations and volatility in oil and gas prices as well as in the domestic credit and capital markets generally may negatively affect the availability and terms of financing.  If we were to secure an alternative borrowing arrangement, we expect that such arrangement will include less favorable terms, including with respect to the cost of borrowing and financial covenants, than those of our current Credit Facility.  If we are unable to secure an alternative borrowing arrangement but are able to repay any amounts understanding under the Credit Facility at maturity with cash on hand, we will nevertheless lose a primary source of liquidity and be required to fund our business and operations going forward without outside capital.  There is no guarantee that we will be able to do so, in which case we may have to significantly reduce our spending and may be unable to execute our existing short-term or long-term business plan and our liquidity and results of operations may be materially adversely affected.  Further, if we are unable to secure an alternative borrowing arrangement and are unable to repay any amounts outstanding at maturity with cash on hand, we would be in default under the Credit Facility as well as under the indenture governing the 2015 Notes, which would also require repayment of the outstanding principal, interest and liquidated damages, if any, on the notes.  In such event, we may consider a sale of our company, our assets or a voluntary reorganization in bankruptcy, or we could be forced into an involuntary reorganization in bankruptcy.

 

During June and August 2011, we raised approximately $8.8 million in net proceeds through the June Offering and the August Offering of 41,000,000 shares of common stock and warrants to purchase 30,250,000 shares of common stock.

 

We intend to use the net proceeds from these Offerings for capital expenditures, working capital, acquisitions of oil and natural gas properties, repayment or refinancing of indebtedness or general corporate purposes.

 

We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We adjust capital expenditures in response to changes in natural gas and oil prices, drilling results and cash flow. If we need additional liquidity for future activities, including paying amounts owed in connection with a borrowing base reduction, if any, we may be required to consider several options for raising additional funds, such as selling securities, selling assets or farm-outs or similar arrangements, but we may be unable to complete any of these transactions on terms acceptable to us or at all.  Any financing obtained through the sale of our equity will likely result in substantial dilution to our stockholders.

 

Sources and Uses of Funds

 

The following table summarizes our sources and uses of cash for each of the nine months ended September 30, 2011 and 2010.

 

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For the Nine Months Ended
September 30,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

Net cash provided by operations

 

$

3,207,080

 

$

3,464,406

 

Net cash (used in) provided by investing activities

 

(6,119,049

)

21,221,340

 

Net cash provided by (used in) financing activities

 

10,416,273

 

(31,651,294

)

Net increase (decrease) in cash

 

7,504,304

 

(6,965,548

)

 

Cash provided by operations decreased by $257,326 from September 30, 2010 to September 30, 2011.  The decrease in cash provided by operations was primarily due to a 9% decrease in equivalent production partially offset by a 28% increase in the oil prices received during the first nine months of 2011.

 

Our investing activities during the first nine months of 2011 included our development and exploration activities, fixed asset additions and the change in advances from joint interest owners. The investing activity during the first nine months of 2010 was comprised of the sales proceeds of $24,309,000 associated primarily with the sale of our gathering and evaporative facilities (see Note 4 — Asset Sales of the accompanying unaudited condensed consolidated financial statements), the sale of a partial working interest in 32 producing wells and development and exploration activities, fixed asset additions and the change in advances from joint interest owners.

 

The financing activity during the first nine months of 2011 included $10.0 million in gross proceeds from the sale of common stock and Warrants in the Offerings, $2.0 million in borrowings under our Credit Facility and the payment of $1,583,727 in costs associated with the common stock and Warrant offerings and the issuance of our 2015 Notes. The financing activity during the first nine months of 2010 was comprised of $29.0 million in repayments of borrowings on our Credit Facility, the payment of $2,096,894 in costs associated with the issuance of our 2015 Notes, the repurchase of 2011 Notes of $54,400 and the payment of a deposit of $500,000 in connection with our gathering agreement with Monarch in February 2010.

 

2011 Capital Budget

 

Our Board of Directors approved an initial capital expenditure budget of $6.0 million for our 2011 oil and gas activities. In the Uinta Basin, we allocated approximately $2.4 million for our continued up-hole recompletion program targeting natural gas and an additional $1.6 million for the drilling and completion of two Green River Formation oil wells. A significant portion of the remaining $2.0 million budget may be allocated to additional investments in existing and new California oil and gas prospects in the San Joaquin Basin. As of September 30, 2011, we had expended approximately $4.3 of the $6.0 million capital expenditure budget.  We expect that the remaining portion of our 2011 budget will be funded primarily from cash on hand, cash flow from operations, cash from the Offerings and borrowings under our Credit Facility; however, our budget is subject to market conditions, drilling results, oilfield service availability and commodity prices.

 

Risk Management

 

We use commodity derivative instruments to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk.  However, these derivative instruments may limit the prices we actually realize and therefore may reduce oil and natural gas revenues in the future. The fair value of our oil and natural gas derivative instruments (excluding the Warrants) outstanding

 

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as of September 30, 2011 was a current asset of $318,143 and a noncurrent asset of $53,772. See Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on our risk management policies.

 

Results of Operations

 

The Third Quarter of 2011 Compared to the Third Quarter of 2010

 

Oil and Gas Revenue and Production

 

The table below sets forth the production volumes, price and revenue by product for the periods presented.

 

 

 

For the Three Months Ended
 September 30,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

Natural gas production (Mcf)

 

879,788

 

1,073,831

 

Average sales price per Mcf

 

$

4.49

 

$

3.75

 

Natural gas revenue

 

$

3,946,424

 

$

4,029,912

 

 

 

 

 

 

 

Oil production (Bbl)

 

8,424

 

11,019

 

Average sales price per Bbl

 

$

74.87

 

$

60.96

 

Oil revenue

 

$

630,703

 

$

671,775

 

 

 

 

 

 

 

Total oil and gas revenue

 

$

4,577,127

 

$

4,701,687

 

 

 

 

 

 

 

Equivalent production (Mcfe)

 

930,332

 

1,139,945

 

 

The decrease in oil and gas revenue of $124,560 during the third quarter of 2011 compared with the third quarter of 2010 was comprised of an 18% decrease in equivalent oil and gas production partially offset by an increase in average oil and gas prices of $13.91 per Bbl of oil and $0.74 per Mcf of gas. The decrease in equivalent oil and gas production was primarily due to a third-party gathering company’s high line pressures, unusually high compressor downtime and normal production declines associated with the tight sand reservoirs on our existing wells. The $124,560 decrease in oil and gas revenue during the third quarter of 2011 represents a decrease of $951,323 related to the equivalent production decrease partially offset by an increase of $826,763 related to the increase in oil and gas prices.

 

Lease Operating Expenses

 

The table below sets forth the detail of oil and gas lease operating expenses during the periods presented.

 

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For the Three
Months Ended
 September 30,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

Direct operating expenses and overhead

 

$

1,061,080

 

$

1,118,533

 

Workover expense

 

804,392

 

89,063

 

Total operating expenses

 

$

1,865,472

 

$

1,207,596

 

Operating expenses per Mcfe

 

$

2.01

 

$

1.06

 

 

 

 

 

 

 

Production and property taxes

 

$

216,609

 

$

214,801

 

Production and property taxes per Mcfe

 

$

0.23

 

$

0.19

 

 

 

 

 

 

 

Total lease operating expense

 

$

2,082,081

 

$

1,422,397

 

 

 

 

 

 

 

Total lease operating expense per Mcfe

 

$

2.24

 

$

1.25

 

 

Lease operating expense increased $659,684 during the third quarter of 2011 compared with the third quarter of 2010. The increase is primarily due to higher workover expenses related to the removal of critical velocity reduction strings, modification of cap strings and scale treatment and removal from existing wells during the third quarter of 2011.

 

Transportation and Processing

 

Transportation and processing costs of $444,561 ($0.48 per Mcfe) and $801,938 ($0.70 per Mcfe) as of September 30, 2011 and 2010, respectively, represent the costs we incurred to transport the gas production from our wells subsequent to the sale of our gathering system as described in Note 4 — Asset Sales of the accompanying unaudited condensed consolidated financial statements. The decrease of $357,377 in these expenses during the third quarter of 2011 reflects lower transportation and processing costs related to the 18% decrease in gas production previously discussed as well as a refund of certain processing costs associated with our natural gas liquids.

 

Depletion, Depreciation, Amortization and Accretion

 

Depletion, depreciation and amortization expense during the third quarters of 2011 and 2010 is comprised of depletion expense related to our oil and gas properties, depreciation expense of furniture, fixtures and equipment and accretion expense related to the asset retirement obligation. The increase of $132,410 during the third quarter of 2011 compared to the third quarter of 2010 was primarily due to the increase in the full cost pool during 2011.

 

Loss on Sale of Assets, net

 

The loss on sale of assets, net during the third quarters of 2011 and 2010 represents the decrease in the fair value of certain of our inventory.

 

General and Administrative Expense

 

The following table summarizes the components of general and administrative expense and stock-based compensation expense incurred during the periods presented.

 

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For the Three
Months Ended
 September 30,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

Total general and administrative costs

 

$

1,262,448

 

$

1,305,762

 

General and administrative costs allocated to drilling, completion and operating activities

 

(311,967

)

(413,423

)

General and administrative expense

 

$

950,481

 

$

892,339

 

General and administrative expenses per Mcfe

 

$

1.02

 

$

0.78

 

 

 

 

 

 

 

Total stock-based compensation costs

 

$

75,081

 

$

332,350

 

Stock-based compensation (costs) reduction in costs capitalized

 

132

 

359

 

Stock-based compensation

 

$

75,213

 

$

332,709

 

Stock-based compensation per Mcfe

 

$

0.08

 

$

0.29

 

 

 

 

 

 

 

Total general and administrative expense including stock-based compensation

 

$

1,025,694

 

$

1,225,048

 

 

 

 

 

 

 

Total general and administrative expense per Mcfe

 

$

1.10

 

$

1.07

 

 

General and administrative expense decreased by $199,354 during the third quarter of 2011 as compared with the third quarter of 2010 due to an increase in general and administrative expenses of $58,142 partially offset by a $257,496 decrease in stock-based compensation. General and administrative expenses remained fairly consistent during the third quarter of 2011 when compared with the expenses in the same period during 2010. The decrease in stock-based compensation expense was due primarily to the fact that a substantial portion of our unvested stock options were being accounted for as liability awards until stockholder approval of the stock plan under which such options were issued was received in July 2011. The remainder of the decrease in the compensation expense associated with these unvested stock options is primarily due to the decrease in the trading price of our common stock during the third quarter of 2011 as compared to the third quarter of 2010.

 

Interest Expense