10-Q 1 a12-20132_110q.htm 10-Q

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-Q

 


 

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

 

For the quarterly period ended September 30, 2012

 

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 001-32960

 


 

GeoMet, Inc.

(Exact name of registrant as specified in its charter)

 


 

Delaware

 

76-0662382

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification Number)

 

909 Fannin, Suite 1850

Houston, Texas 77010

(713) 659-3855

(Address of principal executive offices and telephone number, including area code)

 

N/A

(Former name, former address and former fiscal year, if changed since last report)

 


 

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

 

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).  x  Yes  o  No

 

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 o

 

Smaller reporting company x

 

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

 

As of November 1, 2012, 40,690,077 shares and 5,145,156 shares, respectively, of the registrant’s common stock and preferred stock, par value $0.001 per share, were outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

 

 

 

Part I. Financial Information

 

 

 

 

Item 1.

Consolidated Financial Statements (Unaudited)

 

 

Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011

3

 

Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011

4

 

Consolidated Statements of Comprehensive (Loss) Income for the three and nine months ended September 30, 2012 and 2011

5

 

Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011

6

 

Notes to Consolidated Financial Statements (Unaudited)

7

 

 

 

Item 2.

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

21

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

31

 

 

 

Item 4.

Controls and Procedures

31

 

 

 

Part II. Other Information

 

 

 

 

Item 1.

Legal Proceedings

32

 

 

 

Item 1A.

Risk Factors

32

 

 

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

32

 

 

 

Item 3.

Defaults Upon Senior Securities

32

 

 

 

Item 4.

Mine Safety Disclosures

32

 

 

 

Item 5.

Other Information

32

 

 

 

Item 6.

Exhibits

32

 

2



Table of Contents

 

Part I. FINANCIAL INFORMATION

 

Item  1.                                Financial Statements

 

GEOMET, INC. AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

 

 

 

September 30, 2012

 

December 31, 2011

 

ASSETS

 

 

 

 

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

$

7,006,333

 

$

457,865

 

Accounts receivable, net of allowance of $17,634 at September 30, 2012 and December 31, 2011

 

4,411,710

 

4,402,065

 

Inventory

 

298,807

 

597,197

 

Derivative asset—natural gas contracts

 

6,812,576

 

20,685,187

 

Other current assets

 

1,387,418

 

1,141,310

 

 

 

 

 

 

 

Total current assets

 

19,916,844

 

27,283,624

 

 

 

 

 

 

 

Gas properties—utilizing the full cost method of accounting:

 

 

 

 

 

Proved gas properties

 

534,401,745

 

561,451,504

 

Other property and equipment

 

3,743,084

 

3,671,123

 

 

 

 

 

 

 

Total property and equipment

 

538,144,829

 

565,122,627

 

Less accumulated depreciation, depletion, amortization and impairment of gas properties

 

(453,432,823

)

(388,730,093

)

 

 

 

 

 

 

Property and equipment—net

 

84,712,006

 

176,392,534

 

 

 

 

 

 

 

Other noncurrent assets:

 

 

 

 

 

Derivative asset—natural gas contracts

 

 

1,765,450

 

Deferred income taxes

 

1,421,903

 

48,171,298

 

Other

 

2,037,729

 

3,532,882

 

 

 

 

 

 

 

Total other noncurrent assets

 

3,459,632

 

53,469,630

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

108,088,482

 

$

257,145,788

 

 

 

 

 

 

 

LIABILITIES, MEZZANINE AND STOCKHOLDERS’ (DEFICIT) EQUITY

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

Accounts payable

 

$

8,777,675

 

$

7,500,768

 

Accrued liabilities

 

2,465,657

 

3,936,070

 

Deferred income taxes

 

1,421,903

 

4,153,099

 

Derivative liability—natural gas contracts

 

1,065,545

 

 

Asset retirement obligation

 

 

32,028

 

Current portion of long-term debt

 

14,100,000

 

91,757

 

 

 

 

 

 

 

Total current liabilities

 

27,830,780

 

15,713,722

 

 

 

 

 

 

 

Long-term debt

 

131,500,000

 

158,171,662

 

Asset retirement obligation

 

8,485,761

 

8,138,551

 

Derivative liability—natural gas contracts

 

3,703,048

 

 

Other long-term accrued liabilities

 

151,245

 

8,145

 

 

 

 

 

 

 

TOTAL LIABILITIES

 

171,670,834

 

182,032,080

 

 

 

 

 

 

 

Commitments and contingencies (Note 15)

 

 

 

 

 

Mezzanine equity:

 

 

 

 

 

Series A Convertible Redeemable Preferred Stock—net of offering costs of $1,660,435; redemption amount $49,893,090; $.001 par value; 7,401,832 shares authorized, 4,989,309 and 4,549,537 shares were issued and outstanding at September 30, 2012 and December 31, 2011, respectively

 

33,283,310

 

28,482,624

 

Stockholders’ (Deficit) Equity:

 

 

 

 

 

Preferred stock, $0.001 par value—2,598,168 shares authorized, none issued

 

 

 

Common stock, $0.001 par value—authorized 125,000,000 shares; issued and outstanding 40,690,077 and 40,010,188 at September 30, 2012 and December 31, 2011, respectively

 

40,690

 

40,010

 

Treasury stock—10,432 shares at September 30, 2012 and December 31, 2011

 

(94,424

)

(94,424

)

Paid-in capital

 

196,669,112

 

200,344,209

 

Accumulated other comprehensive income (loss)

 

31,738

 

(1,309,926

)

Retained deficit

 

(293,330,144

)

(152,104,329

)

Less notes receivable

 

(182,634

)

(244,456

)

 

 

 

 

 

 

Total stockholders’ (deficit) equity

 

(96,865,662

)

46,631,084

 

 

 

 

 

 

 

TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ (DEFICIT) EQUITY

 

$

108,088,482

 

$

257,145,788

 

 

See accompanying Notes to Consolidated Financial Statements (Unaudited)

 

3



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

 

Consolidated Statements of Operations (Unaudited)

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Revenues:

 

 

 

 

 

 

 

 

 

Gas sales

 

$

9,609,586

 

$

8,519,980

 

$

27,464,729

 

$

24,701,708

 

Operating fees

 

55,439

 

64,984

 

190,650

 

210,670

 

Total revenues

 

9,665,025

 

8,584,964

 

27,655,379

 

24,912,378

 

Expenses:

 

 

 

 

 

 

 

 

 

Lease operating expense

 

4,417,390

 

2,982,932

 

13,350,417

 

8,793,883

 

Compression and transportation expense

 

2,217,610

 

1,082,145

 

6,757,864

 

2,959,209

 

Production taxes

 

442,129

 

390,045

 

1,276,215

 

1,077,754

 

Depreciation, depletion and amortization

 

2,539,531

 

1,676,872

 

9,460,420

 

4,900,669

 

Impairment of gas properties

 

25,431,734

 

 

83,467,022

 

 

General and administrative

 

1,097,308

 

1,159,422

 

3,765,475

 

4,083,981

 

Restructuring costs

 

187,597

 

 

952,830

 

 

Acquisition costs

 

 

370,621

 

 

370,621

 

Losses (gains) on natural gas derivatives

 

4,783,942

 

(4,225,508

)

(341,525

)

(6,605,612

)

Total operating expenses

 

41,117,241

 

3,436,529

 

118,688,718

 

15,580,505

 

Operating (loss) income

 

(31,452,216

)

5,148,435

 

(91,033,339

)

9,331,873

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Interest income

 

814

 

4,207

 

5,113

 

12,968

 

Interest expense

 

(1,513,684

)

(868,388

)

(4,057,927

)

(2,532,160

)

Write off of debt issuance costs

 

(1,377,520

)

 

(1,377,520

)

 

Other

 

943

 

12,501

 

(3,156

)

8,176

 

Total other income (expense):

 

(2,889,447

)

(851,680

)

(5,433,490

)

(2,511,016

)

 

 

 

 

 

 

 

 

 

 

(Loss) income before income taxes and discontinued operations

 

(34,341,663

)

4,296,755

 

(96,466,829

)

6,820,857

 

Income tax expense

 

(6,250

)

(1,619,739

)

(44,036,950

)

(2,527,036

)

 

 

 

 

 

 

 

 

 

 

(Loss) income before discontinued operations

 

(34,347,913

)

2,677,016

 

(140,503,779

)

4,293,821

 

Discontinued operations, net of tax

 

(25,655

)

(247,141

)

(722,036

)

(341,129

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income

 

$

(34,373,568

)

$

2,429,875

 

$

(141,225,815

)

$

3,952,692

 

Accretion of Series A Convertible Redeemable Preferred Stock

 

(485,338

)

(449,347

)

(1,418,307

)

(1,308,519

)

Paid-in-kind dividends on Series A Convertible Redeemable Preferred Stock

 

(903,912

)

(1,377,880

)

(2,764,257

)

(4,009,990

)

Cash dividends paid on Series A Convertible Redeemable Preferred Stock

 

(689

)

(792

)

(1,985

)

(2,014

)

Net (loss) income available to common stockholders

 

$

(35,763,507

)

$

601,856

 

$

(145,410,364

)

$

(1,367,831

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share—basic:

 

 

 

 

 

 

 

 

 

Net (loss) income per common share from continuing operations

 

$

(0.89

)

$

0.02

 

$

(3.61

)

$

(0.02

)

Net loss per common share from discontinued operations

 

 

 

(0.02

)

(0.01

)

Net (loss) income per common share—basic

 

$

(0.89

)

$

0.02

 

$

(3.63

)

$

(0.03

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share—diluted:

 

 

 

 

 

 

 

 

 

Net (loss) income per common share from continuing operations

 

$

(0.89

)

$

0.02

 

$

(3.61

)

$

(0.02

)

Net loss per common share from discontinued operations

 

 

 

(0.02

)

(0.01

)

Net (loss) income per common share—diluted

 

$

(0.89

)

$

0.02

 

$

(3.63

)

$

(0.03

)

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares:

 

 

 

 

 

 

 

 

 

Basic

 

40,286,573

 

39,640,275

 

40,018,778

 

39,576,684

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

40,286,573

 

39,968,064

 

40,018,778

 

39,576,684

 

 

See accompanying Notes to Consolidated Financial Statements (Unaudited)

 

4



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

 

Consolidated Statements of Comprehensive (Loss) Income

(Unaudited)

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Net (loss) income

 

$

(34,373,568

)

$

2,429,875

 

$

(141,225,815

)

$

3,952,692

 

Gain on foreign currency translation adjustment

 

14,240

 

3,342

 

2,019

 

4,082

 

Reclassification adjustment for loss on foreign currency translation included in net loss

 

 

 

1,307,906

 

 

Unrealized (loss) gain on available for sale securities

 

(19,454

)

 

31,738

 

 

Gain on interest rate swap

 

 

 

 

10,862

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive (loss) income

 

$

(34,378,782

)

$

2,433,217

 

$

(139,884,152

)

$

3,967,636

 

 

See accompanying Notes to Consolidated Financial Statements (Unaudited)

 

5



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

 

Consolidated Statements of Cash Flows

(Unaudited)

 

 

 

Nine months ended September 30,

 

 

 

2012

 

2011

 

Cash flows provided by operating activities:

 

 

 

 

 

Net (loss) income

 

$

(141,225,815

)

$

3,952,692

 

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

 

 

 

 

 

Depreciation, depletion and amortization

 

9,458,700

 

5,142,308

 

Impairment of gas properties

 

83,467,022

 

 

Amortization of debt issuance costs

 

530,799

 

435,702

 

Write off of debt issuance costs

 

1,377,520

 

 

Deferred income tax expense

 

44,018,200

 

2,508,286

 

Unrealized losses from the change in market value of open derivative contracts

 

13,258,958

 

122,246

 

Stock-based compensation

 

512,377

 

576,345

 

Loss on sale of Hudson’s Hope Gas, Ltd.

 

683,154

 

 

Loss on sale of other assets

 

5,200

 

1,164

 

Accretion expense—asset retirement obligation

 

584,813

 

407,708

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(13,052

)

127,815

 

Other assets

 

193,953

 

(715,323

)

Accounts payable

 

1,577,480

 

(401,321

)

Other accrued liabilities

 

(833,930

)

(574,953

)

Net cash provided by operating activities

 

13,595,379

 

11,582,669

 

 

 

 

 

 

 

Cash flows provided by (used in) investing activities:

 

 

 

 

 

Capital expenditures

 

(856,655

)

(12,118,713

)

Return of original basis through the settlement of natural gas derivative contracts

 

7,147,696

 

 

Proceeds from sale of other property and equipment

 

3,500

 

 

Other assets

 

 

246,134

 

Net cash provided by (used in) investing activities

 

6,294,541

 

(11,872,579

)

 

 

 

 

 

 

Cash flows (used in) provided by financing activities:

 

 

 

 

 

Proceeds from revolving credit facility borrowings

 

10,500,000

 

24,300,000

 

Payments on revolving credit facility

 

(22,800,000

)

(23,800,000

)

Proceeds from exercise of stock options

 

 

3,791

 

Deferred financing costs

 

(853,578

)

(172,507

)

Payments on other debt

 

(188,965

)

(111,083

)

Purchase and cancellation of treasury stock

 

(2,039

)

(2,145

)

Cash dividends paid on Series A Convertible Redeemable Preferred Stock

 

(1,985

)

(2,014

)

Net cash (used in) provided by financing activities

 

(13,346,567

)

216,042

 

 

 

 

 

 

 

Effect of exchange rate changes on cash

 

5,115

 

57

 

 

 

 

 

 

 

Increase (decrease) in cash and cash equivalents

 

6,548,468

 

(73,811

)

Cash and cash equivalents at beginning of period

 

457,865

 

536,533

 

 

 

 

 

 

 

Cash and cash equivalents at end of period

 

$

7,006,333

 

$

462,722

 

 

 

 

 

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid during the period for interest expense

 

$

5,960,054

 

$

2,573,915

 

 

 

 

 

 

 

Cash paid during the period for income taxes

 

$

18,750

 

$

18,750

 

 

 

 

 

 

 

Significant noncash investing and financing activities:

 

 

 

 

 

Accrued capital expenditures

 

$

609,017

 

$

1,484,715

 

Fair value of common stock received in exchange for Hudson’s Hope Gas, Ltd.

 

$

293,769

 

$

 

 

See accompanying Notes to Consolidated Financial Statements (Unaudited)

 

6



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

 

Notes to Consolidated Financial Statements

(Unaudited)

 

Note 1—Organization and Our Business

 

GeoMet, Inc. (“GeoMet,” “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the laws of the State of Delaware on November 9, 2000. We are a natural gas producer primarily involved in the exploration, development and production of natural gas from coal seams (coalbed methane). Our principal operations and producing properties are located in Alabama, Virginia and West Virginia.

 

The accompanying unaudited consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. All intercompany transactions and balances have been eliminated in consolidation. The unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the financial position as of, and results of operations for, the interim periods presented. These unaudited consolidated financial statements have been prepared in accordance with the guidelines of interim reporting; therefore, they do not include all disclosures required for our year-end audited consolidated financial statements prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Interim period results are not necessarily indicative of results of operations or cash flows for the full year. These unaudited consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements for the fiscal year ended December 31, 2011 and the accompanying notes included in our Annual Report on Form 10-K, which we filed with the Securities and Exchange Commission (the “SEC”) on March 30, 2012.

 

Note 2—Liquidity Considerations

 

As of September 30, 2012, we had a working capital deficit of $7.9 million.  The working capital deficit as of September 30, 2012 was primarily the result of the classification of $14.1 million of our borrowings under our Fifth Amended and Restated Credit Agreement (the “Credit Agreement”), as described in Note 11—Long-Term Debt, as a current liability for scheduled payments over the next twelve months.  We believe that our cash flows from operating activities, as well as the return of original basis through the settlement of natural gas derivative contracts, will provide us with sufficient resources to fund our working capital deficit and to meet our obligations in connection with operating our properties for at least the next twelve months. However, there can be no assurance that future borrowing base determinations will not result in additional payment obligations under the Credit Agreement or that our cash flows will not be adversely impacted by events beyond our control.

 

Note 3—Recent Pronouncements

 

On June 16, 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-05, Presentation of Comprehensive Income, which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. The ASU does not change the items that must be reported in other comprehensive income. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company has adopted and applied the provisions of this update for the three and nine months ended September 30, 2012.

 

On May 12, 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”). The ASU is the result of joint efforts by the FASB and IASB to develop a single, converged fair value framework—that is, converged guidance on how (not when) to measure fair value and on what disclosures to provide about fair value measurements. Thus, there are few differences between the ASU and its international counterpart, IFRS 13. While the ASU is largely consistent with existing fair value measurement principles in U.S. GAAP, it expands ASC 820’s existing disclosure requirements for fair value measurements and makes other amendments. Many of these amendments were made to eliminate unnecessary wording differences between U.S. GAAP and IFRS. However, some could change how the fair value measurement guidance in ASC 820 is applied. The ASU is effective for interim and annual periods beginning after December 15, 2011. The Company has adopted and applied the provisions of this update for the three and nine months ended September 30, 2012. See disclosure provided in these Notes to Consolidated Financial Statements (Unaudited).

 

7



Table of Contents

 

Note 4—Net (Loss) Income Per Common Share

 

Net (loss) income per common share—basic is calculated by dividing Net (loss) income available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net (loss) income per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net (loss) income available to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net (loss) income per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares would have an anti-dilutive effect. A reconciliation of Net (loss) income per common share is as follows:

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

 

$

(34,373,568

)

$

2,429,875

 

$

(141,225,815

)

$

3,952,692

 

 

 

 

 

 

 

 

 

 

 

Accretion of Series A Convertible Redeemable Preferred Stock

 

(485,338

)

(449,347

)

(1,418,307

)

(1,308,519

)

Paid-in-kind dividends on Series A Convertible Redeemable Preferred Stock

 

(903,912

)

(1,377,880

)

(2,764,257

)

(4,009,990

)

Cash dividends paid on Series A Convertible Redeemable Preferred Stock

 

(689

)

(792

)

(1,985

)

(2,014

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income available to common stockholders

 

$

(35,763,507

)

$

601,856

 

$

(145,410,364

)

$

(1,367,831

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share—basic:

 

 

 

 

 

 

 

 

 

Net (loss) income per common share from continuing operations

 

$

(0.89

)

$

0.02

 

$

(3.61

)

$

(0.02

)

Net loss per common share from discontinued operations

 

 

 

(0.02

)

(0.01

)

Net (loss) income per common share—basic

 

$

(0.89

)

$

0.02

 

$

(3.63

)

$

(0.03

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share—diluted:

 

 

 

 

 

 

 

 

 

Net (loss) income per common share from continuing operations

 

$

(0.89

)

$

0.02

 

$

(3.61

)

$

(0.02

)

Net loss per common share from discontinued operations

 

 

 

(0.02

)

(0.01

)

Net (loss) income per common share—diluted

 

$

(0.89

)

$

0.02

 

$

(3.63

)

$

(0.03

)

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares:

 

 

 

 

 

 

 

 

 

Basic

 

40,286,573

 

39,640,275

 

40,018,778

 

39,576,684

 

Add potentially dilutive securities:

 

 

 

 

 

 

 

 

 

Stock options, non-vested restricted stock and non-vested restricted stock units

 

 

327,789

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

40,286,573

 

39,968,064

 

40,018,778

 

39,576,684

 

 

Net loss per common share—diluted for the three months ended September 30, 2012 excluded the effect of outstanding options exercisable to purchase 2,397,603 shares, 116,732 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 273,301 weighted average restricted shares outstanding, and 4,838,181 shares of Series A Convertible Redeemable Preferred Stock (37,216,776 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

 

Net loss per common share—diluted for the nine months ended September 30, 2012 excluded the effect of outstanding options exercisable to purchase 2,397,603 shares, 170,570 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 262,896 weighted average restricted shares outstanding, and 4,549,537 shares of Series A Convertible Redeemable Preferred Stock (34,996,440 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

 

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Table of Contents

 

Net income per common share—diluted for the three months ended September 30, 2011 excluded the effect of 4,411,749 shares of Series A Convertible Redeemable Preferred Stock (33,936,532 in dilutive shares, as converted, which assumes conversion on the first day of the period) because their effect would have been anti-dilutive. In accordance with ASC 260, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any preferred dividends and accretion unless the preferred shares are anti-dilutive. As such, there was no add back to Net income available to common stockholders for the three months ended September 30, 2011 for accretion of, and dividends paid for, Series A Convertible Redeemable Preferred Stock (cash and PIK) of $449,347 and $1,378,672, respectively, in computing Net income per common share—diluted as the preferred shares were anti-dilutive.

 

Net loss per common share—diluted for the nine months ended September 30, 2011 excluded the effect of outstanding options exercisable to purchase 2,603,536 shares, 232,089 restricted stock units for which common shares are distributed upon achievement of certain performance targets, 355,705 weighted average restricted shares outstanding, and 4,148,538 shares of Series A Convertible Redeemable Preferred Stock (31,911,830 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive. For the preferred shares, there was no add back to Net loss available to common stockholders for the nine months ended September 30, 2011 for accretion of, and dividends paid for, Series A Convertible Redeemable Preferred Stock (cash and PIK) of $1,308,519 and $4,012,004, respectively, in computing Net loss per common share—diluted as the preferred shares were anti-dilutive.

 

Note 5—Discontinued Operations

 

On June 20, 2012, we disposed of Hudson’s Hope Gas, Ltd., a subsidiary which held our Canadian gas properties, in exchange for two million shares of Canada Energy Partners, Inc. (“CEP Shares”) which we are restricted from selling before June 20, 2013. We recognized a loss on the disposition in the amount of $0.7 million, which was made up of a $1.3 million loss related to the currency translation adjustment, offset by $0.3 million in asset retirement obligations conveyed to the buyer and the proceeds consisting of the $0.3 million in estimated fair value of the CEP shares received. The loss on this disposition has been included in Discontinued operations, net of tax, in the Consolidated Statements of Operations (Unaudited). Additionally, all historical operating results related to the disposed company have been removed from Operating (loss) income and included in Discontinued operations, net of tax, in the Consolidated Statements of Operations (Unaudited) for all periods presented.

 

As a result of the disposition, we are classifying these activities as a discontinued operation for all the periods presented. Results for activities reported as discontinued operations were as follows:

 

Statements of Operations (Unaudited):

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Revenues

 

$

 

$

 

$

 

$

 

Total operating expenses

 

 

(247,141

)

(13,123

)

(341,129

)

 

 

 

 

 

 

 

 

 

 

Operating loss

 

 

(247,141

)

(13,123

)

(341,129

)

Loss on sale of Hudson’s Hope Gas, Ltd.

 

 

 

(683,154

)

 

Other expense

 

(25,655

)

 

(25,759

)

 

Income tax expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

$

(25,655

)

$

(247,141

)

$

(722,036

)

$

(341,129

)

 

9



Table of Contents

 

Balance Sheets (Unaudited):

 

 

 

September 30, 2012

 

December 31, 2011

 

ASSETS

 

 

 

 

 

Total current assets

 

$

 

$

33,474

 

Gas properties—utilizing the full cost method of accounting:

 

 

 

 

 

Proved gas properties

 

 

28,073,293

 

Less accumulated depreciation, depletion, amortization and impairment of gas properties

 

 

(28,073,293

)

 

 

 

 

 

 

Property and equipment—net

 

 

 

Total other noncurrent assets

 

 

2,941

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

 

$

36,415

 

 

 

 

 

 

 

LIABILITIES, MEZZANINE AND STOCKHOLDERS’ (DEFICIT) EQUITY

 

 

 

 

 

Total current liabilities

 

$

 

$

54,827

 

Asset retirement obligation

 

 

303,169

 

 

 

 

 

 

 

TOTAL LIABILITIES

 

 

357,996

 

Total stockholders’ deficit

 

 

(321,581

)

 

 

 

 

 

 

TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ (DEFICIT) EQUITY

 

$

 

$

36,415

 

 

Note 6—Gas Properties

 

The method of accounting for oil and gas producing activities determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for gas properties as prescribed by the SEC. Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties are capitalized.

 

Natural gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved gas reserves.

 

Estimation of proved gas reserves involves professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during future reporting periods. No gains or losses are recognized upon the sale or disposition of gas properties unless the sale or disposition represents a significant quantity of gas reserves, which would have a significant impact on the depreciation, depletion and amortization rate.

 

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of estimated future net revenues, discounted at 10% per annum, plus cost of properties not being amortized plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and stockholders’ (deficit) equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.

 

The ceiling test is calculated using the unweighted arithmetic average of the natural gas price on the first day of each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions, as allowed by the guidelines of the SEC. In addition, subsequent to the adoption of ASC 410-20-25, the future cash outflows associated with settling asset retirement obligations were not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.

 

For the twelve months ended September 30, 2012, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $2.84 per Mcf, resulting in a natural gas price of $2.99 per Mcf when adjusted for regional price

 

10



Table of Contents

 

differentials. For the three and nine months ended September 30, 2012, we recorded a $25.4 million and $83.5 million write-down, respectively, of the carrying value of our U.S. full cost pool.

 

Note 7—Asset Retirement Obligation

 

We record an asset retirement obligation (“ARO”) on the Consolidated Balance Sheets (Unaudited) and capitalize the asset retirement costs in gas properties in the period in which the retirement obligation is incurred. The amount of the ARO and the costs capitalized are equal to the estimated future costs to satisfy the obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date we incurred the abandonment obligation using an assumed interest rate. Once the ARO is recorded, it is then accreted to its estimated future value using the same assumed interest rate. Asset retirement obligations incurred in the current period were non-recurring Level 3 (unobservable inputs) fair value measurements under ASC 820-10-55. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

 

The following table details the changes to our asset retirement obligation for the nine months ended September 30, 2012:

 

Current portion of liability at January 1, 2012

 

$

32,028

 

Add: Long-term asset retirement obligation at January 1, 2012

 

8,138,551

 

 

 

 

 

Asset retirement obligation at January 1, 2012

 

8,170,579

 

Liabilities incurred

 

14,252

 

Liabilities conveyed to buyer of Hudson’s Hope Gas, Ltd.

 

(345,226

)

Settlements

 

(184,570

)

Accretion

 

584,813

 

Revisions in estimates

 

241,317

 

Foreign currency translation

 

4,596

 

Asset retirement obligation at September 30, 2012

 

8,485,761

 

Less: Current portion of liability

 

 

 

 

 

 

Long-term asset retirement obligation

 

$

8,485,761

 

 

Note 8—Derivative Instruments and Hedging Activities

 

The energy markets have historically been volatile, and there can be no assurance that future natural gas prices will not be subject to wide fluctuations. In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has adopted a policy of hedging natural gas prices primarily using derivative instruments in the form of three-way collars, traditional collars and swaps. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.

 

We enter into hedging transactions, generally for forward periods up to two years or more, which increase the probability of achieving our targeted level of cash flows. Our Credit Agreement limits amounts of future natural gas production that we may hedge.

 

Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling (a sold ceiling) and a minimum floor (a bought floor) future price. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in our Consolidated Balance Sheets (Unaudited) and Consolidated Statements of Operations (Unaudited).

 

11



Table of Contents

 

Commodity Price Risk and Related Hedging Activities

 

At September 30, 2012, we had the following natural gas collar positions:

 

Period

 

Volume
(MMBtu)

 

Sold
Ceiling

 

Bought
Floor

 

Sold
Floor

 

Fair
Value

 

January 2014 through December 2015

 

3,650,000

 

$

4.30

 

$

3.60

 

 

$

(910,759

)

January 2014 through December 2015

 

3,650,000

 

$

4.20

 

$

3.50

 

 

(1,150,697

)

 

 

7,300,000

 

 

 

 

 

 

 

$

(2,061,456

)

 

At September 30, 2012, we had the following natural gas swap positions:

 

Period

 

Volume
(MMBtu)

 

Fixed
Price

 

Fair
Value

 

October through December 2012

 

138,000

 

$

5.11

 

$

247,007

 

October through December 2012

 

57,000

 

$

5.12

 

102,594

 

October through December 2012

 

259,995

 

$

6.85

 

917,949

 

October through December 2012

 

119,616

 

$

6.99

 

438,504

 

October through December 2012

 

196,358

 

$

7.05

 

735,451

 

October 2012

 

124,000

 

$

5.73

 

335,664

 

October 2012

 

248,000

 

$

4.94

 

474,170

 

October 2012

 

465,000

 

$

2.89

 

(61,831

)

November 2012 through March 2013

 

604,000

 

$

6.42

 

1,669,840

 

November 2012 through March 2013

 

906,000

 

$

5.50

 

1,677,012

 

November 2012 through March 2014

 

4,128,000

 

$

3.81

 

(196,105

)

November 2012 through March 2014

 

4,128,000

 

$

3.82

 

(157,375

)

January 2013 through December 2013

 

2,190,000

 

$

3.60

 

(498,957

)

April 2013 through December 2013

 

2,750,000

 

$

3.25

 

(1,582,967

)

 

 

16,313,969

 

 

 

$

4,100,956

 

 

At December 31, 2011, we had the following natural gas swap positions:

 

Period

 

Volume
(MMBtu)

 

Fixed
Price

 

Fair
Value

 

January through March 2012

 

364,000

 

$

7.12

 

$

1,487,299

 

January through March 2012

 

364,000

 

$

6.12

 

1,121,787

 

January through March 2012

 

546,000

 

$

5.08

 

1,118,044

 

January through December 2012

 

552,000

 

$

5.11

 

1,028,519

 

January through December 2012

 

228,000

 

$

5.12

 

427,089

 

January through December 2012

 

1,070,715

 

$

6.85

 

3,851,739

 

January through December 2012

 

528,995

 

$

6.99

 

1,977,837

 

January through December 2012

 

859,269

 

$

7.05

 

3,239,221

 

July through October 2012

 

856,000

 

$

5.73

 

2,137,811

 

July through October 2012

 

1,712,000

 

$

4.94

 

2,923,067

 

November 2012 through March 2013

 

604,000

 

$

6.42

 

1,575,321

 

November 2012 through March 2013

 

906,000

 

$

5.50

 

1,544,680

 

 

 

8,590,979

 

 

 

$

22,432,414

 

 

At September 30, 2012, we had the following natural gas basis swap position:

 

Period

 

Volume
(MMBtu)

 

Fixed
Basis

 

Fair
Value

 

October through December 2012

 

138,000

 

$

0.04

 

$

4,483

 

 

At December 31, 2011, we had the following natural gas basis swap position:

 

Period

 

Volume
(MMBtu)

 

Fixed
Basis

 

Fair
Value

 

July through December 2012

 

552,000

 

$

0.04

 

$

18,223

 

 

12



Table of Contents

 

As of September 30, 2012, we had the following forward sales at NYMEX plus a fixed basis:

 

Period

 

Volume
(MMBtu)

 

Fixed
Basis

 

October 2012 through March 2013

 

910,000

 

$

0.19

 

November 2012 through March 2013

 

1,540,200

 

$

0.22

 

 

 

2,450,200

 

 

 

 

We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants in our Credit Agreement and the collateral for the outstanding borrowings under our Credit Agreement is used as collateral for our hedges. We do not have rights to collateral from our counterparties, nor do we have rights of offset against borrowings under our Credit Agreement.

 

The application of ASC 820-10-55, Fair Value Measurements, currently applies to our derivative instruments. Under the provisions of ASC 820-10-55, we estimate the fair value of our natural gas derivative contracts using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discounted value. ASC 820-10-55 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our counterparties’ and our credit risk, we have considered the effect of credit risk on the fair value of the assets and liabilities related to the items stated below. The consideration for discounting our counterparties’ liabilities (our assets) was based on the difference between the S&P credit rating of a comparable company to our counterparties and the 13-week Treasury bill rate, both at the reporting date. The consideration for discounting our liabilities was based on the difference between the market weighted average cost of debt capital plus a premium over the capital asset pricing model and the stated interest rates of the debt instruments included in our long-term debt.

 

In order to estimate the fair value of our natural gas derivative contracts, a forward price curve and volatility estimates were compiled from sources that include NYMEX settlements and observed trading activity in the Over-the-Counter (“OTC”) markets. Pricing estimates for the theoretical market value of hedge positions were developed using analytical models accepted and employed by a broad cross-section of industry participants. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows.

 

We did not have any transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three and nine months ended September 30, 2012. Based on the use of observable market inputs, we have designated these types of instruments as Level 2 for ASC 820-10-55 reporting purposes. The fair value of our derivative instruments was as follows:

 

 

 

Asset Derivatives

 

Liability Derivatives

 

 

 

September 30, 2012

 

December 31, 2011

 

September 30, 2012

 

December 31, 2011

 

 

 

Balance Sheet
Location

 

Fair
Value

 

Balance Sheet
Location

 

Fair
Value

 

Balance Sheet
Location

 

Fair
Value

 

Balance Sheet
Location

 

Fair
Value

 

Derivatives not designated as hedging instruments under ASC 815-20-25

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas hedge positions

 

Derivative asset (current)

 

$

6,812,576

 

Derivative asset (current)

 

$

20,685,187

 

Derivative liability (current)

 

$

1,065,545

 

Derivative liability (current)

 

$

 

Natural gas hedge positions

 

Derivative asset (non-current)

 

 

Derivative asset (non-current)

 

1,765,450

 

Derivative liability (non-current)

 

3,703,048

 

Derivative liability (non-current)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total derivatives not designated as hedging instruments under ASC 815-20-25

 

 

 

$

6,812,576

 

 

 

$

22,450,637

 

 

 

$

4,768,593

 

 

 

$

 

 

13



Table of Contents

 

Losses (gains) on natural gas derivatives included in the Consolidated Statements of Operations (Unaudited) and Other Comprehensive (Loss) Income (Unaudited) (“OCI”) are as follows:

 

 

 

 

 

Amount of (Gain) or Loss
Recognized in Income on
Derivative

 

 

 

Location of (Gain)

 

Three months ended

 

Nine months ended

 

Derivatives (not designated as hedging

 

or Loss Recognized in

 

September 30,

 

September 30,

 

instruments under ASC 815-20-25)

 

Income on Derivative

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas collar/swap settled positions

 

Losses (gains) on natural gas derivatives

 

$

(3,496,348

)

$

(1,681,756

)

$

(13,600,483

)

$

(6,714,874

)

Natural gas collar/swap unsettled positions

 

Losses (gains) on natural gas derivatives

 

8,280,290

 

(2,543,752

)

13,258,958

 

109,262

 

 

 

 

 

 

 

 

 

 

 

 

 

Losses (gains) on natural gas derivatives 

 

 

 

$

4,783,942

 

$

(4,225,508

)

$

(341,525

)

$

(6,605,612

)

 

We had an interest rate swap mature on January 6, 2011 that had previously been designated as cash flow hedges under ASC 815-20-25.  On the maturity date, a loss of $17,782 was released from Accumulated Other Comprehensive Income (Loss) in the Consolidated Balance Sheet (Unaudited) and recognized as Interest expense in the Consolidated Statements of Operations (Unaudited).

 

Note 9—Investment in CEP Shares

 

At September 30, 2012, we own two million shares of Canada Energy Partners (“CEP”), discussed in Note 5—Discontinued Operations, which we classify as available for sale and record at fair value in Other noncurrent assets on the Consolidated Balance Sheets (Unaudited) based on the closing price of the shares on the TSX Venture Exchange on that date. Gains or losses on the shares of CEP are held in Accumulated other comprehensive income (loss), net of tax. At September 30, 2012, the value of the shares recorded in Other noncurrent assets was $330,721 using a Level 1 input. Accumulated other comprehensive income of $31,738 as of September 30, 2012 consisted entirely of unrealized gains on the CEP shares. Accumulated other comprehensive loss of $1,309,926 as of December 31, 2011 consisted entirely of foreign currency translation adjustments.

 

Note 10—Restructuring Costs

 

Restructuring activities consist of senior management and board of directors realignment.  The restructuring costs for the three months ended September 30, 2012 of $0.2 million included cash payments to our former Chief Executive Officer (“CEO”) of $0.1 million under a consulting agreement and other costs of $0.1 million. The restructuring costs for the nine months ended September 30, 2012 of $1.0 million included cash payments to our former CEO of $0.7 million under separation and consulting agreements, share-based awards conveyed to our former CEO of $0.1 million and other costs of $0.2 million.

 

Note 11—Long-Term Debt

 

On November 18, 2011, our Credit Agreement with a group of six banks became effective. Effective August 8, 2012, we entered into the Fourth Amendment (the “Amendment”) to our Credit Agreement. Borrowings under the Credit Agreement at August 8, 2012 totaled $148.6 million. The Amendment provides for an initial conforming borrowing base of $115.0 million (“Tranche A”) with the balance then remaining in the amount of $33.6 million constituting a non-conforming tranche (“Tranche B”).  The borrowing base will be determined as of each June and December with the next determination scheduled to be completed by December 31, 2012.  Upon any determination of the borrowing base, the redetermined amount of the conforming borrowing base shall constitute a new Tranche A, with any decrease in Tranche A causing an automatic corresponding increase in Tranche B, subject to certain limitations described below, and any increase in Tranche A causing an automatic corresponding decrease in Tranche B. At the next borrowing base determination, Tranche B shall not increase by more than fifty percent (50%) of the amount of the principal payments made on Tranche B Loans since the prior redetermination of the borrowing base.  Thereafter, at each subsequent redetermination of the borrowing base, Tranche B shall not increase by more than twenty-five percent (25%) of the amount of the principal payments made on Tranche B Loans since the prior redetermination of the borrowing base.  Should a future determination of the borrowing base result in the amount of the Tranche B Loan exceeding $33.6 million, the Company has 30 days to repay such excess. The Credit Agreement, as amended, no longer provides for loans to be available on a revolving basis up to the amount of the borrowing base. As a result, the current outstanding loans, once repaid, may not be re-borrowed by the Company. All outstanding borrowings under the Credit Agreement, as amended, are due and payable on April 1, 2014. In addition, the Amendment obligates us to reduce our borrowings under the Credit Agreement, as amended, monthly by an amount equal to our bank cash, excluding the segregated account, minus (i) all outstanding and unpaid checks or Automated Clearing House payments and (ii) an amount equal to $1,000,000 as calculated on the 24th day of each month. The Amendment provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 2.00% on Tranche A Loans and 4.00% on

 

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Table of Contents

 

Tranche B Loans or the London Interbank Offered Rate (the “LIBOR Rate”) plus a margin of 3.00% on Tranche A loans and 5.00% on Tranche B Loans. Adjusted Base Rate is defined to be the greater of (i) the agent’s base rate or (ii) the federal funds rate plus one half of one percent or (iii) the LIBOR Rate plus a margin of 1.00%. The banks will be paid an additional fee based on the amount of Tranche B Loans as follows:

 

Calculation Date

 

Fee Amount (basis points)

 

Date Payable

 

11/25/2012

 

75 bps

 

12/1/2012

 

2/25/2013

 

100 bps

 

3/1/2013

 

5/25/2013

 

125 bps

 

6/1/2013

 

8/25/2013

 

150 bps

 

9/1/2013

 

11/25/2013

 

175 bps

 

12/1/2013

 

 

All financial covenants were deleted by the Amendment and were replaced with a capital expenditure covenant (a maximum of $1.5 million in 2012 and $1.0 million in 2013) and a maximum debt covenant as follows:

 

Quarter Ending

 

Maximum Principal
Outstanding

 

9/30/2012

 

$

146,200,000

 

12/31/2012

 

$

139,300,000

 

3/31/2013

 

$

136,000,000

 

6/30/2013

 

$

132,700,000

 

9/30/2013

 

$

131,500,000

 

12/31/2013

 

$

129,000,000

 

 

Deferred financing costs were $0.4 million and $0.9 million for the three and nine months ended September 30, 2012, respectively, which included an amendment fee of 50 basis points on the amount of Tranche B which was capitalized in Deferred financing costs in the amount of $0.2 million on August 8, 2012 in connection with the execution of the Amendment. Deferred financing costs of $1.4 million as of August 8, 2012 related to the Credit Agreement prior to the Amendment were written off upon execution of the Amendment.

 

As of September 30, 2012, we had $145.6 million of borrowings outstanding under our Credit Agreement. As of September 30, 2012, the interest rates applied to borrowings under Tranche A and Tranche B were 3.24% and 5.24%, respectively. As of December 31, 2011, the weighted average interest rate applied to all borrowings was 2.84%.

 

For the three months ended September 30, 2012, we borrowed no amounts and made payments of $3.0 million under the Credit Agreement. For the nine months ended September 30, 2012, we borrowed $10.5 million and made payments of $22.8 million under the Credit Agreement.

 

For the three months ended September 30, 2011, we borrowed $8.5 million and made payments of $6.9 million under the Credit Agreement. For the nine months ended September 30, 2011, we borrowed $24.3 million and made payments of $23.8 million under the Credit Agreement.

 

For the three months ended September 30, 2012 and 2011, interest on the borrowings averaged 3.50% and 3.45% per annum, respectively. For the nine months ended September 30, 2012 and 2011, interest on the borrowings averaged 3.12% and 3.41% per annum, respectively.

 

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The following is a summary of our long-term debt at September 30, 2012 and December 31, 2011:

 

 

 

September 30,
2012

 

December 31,
2011

 

Borrowings under Credit Agreement:

 

 

 

 

 

Tranche A

 

$

115,000,000

 

$

 

Tranche B

 

30,600,000

 

 

Revolving facility

 

 

157,900,000

 

Note payable to an individual, semi-monthly installments of $644, through September 2015, interest-bearing at 12.6% annually, unsecured

 

 

78,012

 

Salary continuation payable to an individual, semi-monthly installments of $3,958, through December 2015, non-interest-bearing (less amortization discount of $572,074, with an effective rate of 8.25%), unsecured

 

 

285,407

 

 

 

 

 

 

 

Total debt

 

145,600,000

 

158,263,419

 

Less current maturities included in current liabilities

 

(14,100,000

)

(91,757

)

 

 

 

 

 

 

Total long-term debt

 

$

131,500,000

 

$

158,171,662

 

 

We record our debt instruments based on contractual terms. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. On January 1, 2012, we adopted ASU 2011-04 “Fair Value Measurement” which requires the categorization by level of the fair value hierarchy for items not measured at fair value on our Consolidated Balance Sheets (Unaudited) but for which fair value is required to be disclosed. We measure the fair value of our debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 or 2 within the fair value hierarchy. ASC 820-10-55 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our credit risk, we have considered the effect of our credit risk on the fair value of the long-term debt. This consideration involved discounting our long-term debt based on the difference between the market weighted average cost of equity capital plus a premium over the capital asset pricing model and the stated interest rates of the debt instruments included in our long-term debt.  The fair value of long-term debt at September 30, 2012 and December 31, 2011 was estimated to be approximately $136.9 million and $131.1 million, respectively.

 

Note 12—Common Stock

 

At September 30, 2012 and December 31, 2011, there were 40,690,077 and 40,010,188 shares, respectively, of common stock outstanding, both including 10,432 shares of treasury stock held by the Company. Also included in common stock outstanding at September 30, 2012 and December 31, 2011 were 254,260 and 293,166 shares of restricted stock, respectively. The following table details the activity related to our common stock for the nine months ended September 30, 2012:

 

 

 

Date

 

Shares

 

Common stock outstanding at December 31, 2011

 

 

 

40,010,188

 

Purchased by the Company and cancelled for the payment of withholding taxes due on vested shares of restricted stock

 

1/5/2012

 

(1,981

)

Issued to our independent directors (12.5% of annual retainer)

 

3/28/2012

 

64,284

 

Shares Issued under the separation agreement of our former CEO

 

4/30/2012

 

99,108

 

Purchased by the Company and cancelled for the payment of withholding taxes due on vested shares of restricted stock

 

3/15/2012

 

(1,171

)

Issued to our independent directors (12.5% of annual retainer)

 

5/11/2012

 

97,824

 

Purchased by the Company and cancelled for the payment of withholding taxes due on vested shares of restricted stock

 

6/15/2012

 

(418

)

Restricted shares granted to executive officers

 

5/14/2012

 

150,000

 

Issued to our independent directors (12.5% of annual retainer)

 

8/10/2012

 

300,000

 

Restricted shares forfeited upon employment termination

 

6/25/2012

 

(27,757

)

Common stock outstanding at September 30, 2012

 

 

 

40,690,077

 

 

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Note 13—Series A Convertible Redeemable Preferred Stock

 

At September 30, 2012 and December 31, 2011, 4,989,309 and 4,549,537 shares of preferred stock were issued and outstanding, respectively. At September 30, 2012, an additional 2,412,523 shares of our Series A Convertible Redeemable Preferred Stock (“Preferred Stock”) are reserved exclusively for the payment of paid-in-kind dividends (“PIK dividends”). We measure the fair value of PIK dividends using a discounted cash flow analysis based on our current borrowing rates (categorized as level 3).

 

The following table details the activity related to the Preferred Stock for the nine months ended September 30, 2012:

 

 

 

Dividend Period
(Three Months Ended)

 

Date Issued

 

Number of Shares

 

Balance

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2011

 

 

 

 

 

4,549,537

 

$

28,482,624

 

Accretion of Preferred Stock

 

 

 

 

 

 

 

1,418,307

 

PIK Dividends Issued for Preferred Stock :

 

12/31/11

 

1/3/12

 

142,095

 

1,522,035

 

 

 

3/31/12

 

4/2/12

 

146,549

 

1,240,719

 

 

 

6/30/12

 

7/2/12

 

151,128

 

619,625

 

 

 

 

 

 

 

 

 

 

 

Balance At September 30, 2012

 

 

 

 

 

4,989,309

 

$

33,283,310

 

 

On September 6, 2012, we declared a quarterly dividend of 155,847 shares of Preferred Stock covering the period July 1, 2012 through September 30, 2012. As those shares were not issued until October 1, 2012, they have not been included in the Preferred Stock balance at September 30, 2012. As such, we recorded a dividend payable in Current liabilities in the Consolidated Balance Sheet (Unaudited) at September 30, 2012 at an estimated fair value of $864,951. Additionally, on March 31, 2012, June 30, 2012 and September 30, 2012, cash dividends of $645, $651 and $689, respectively, were paid for fractional share dividends not paid-in-kind.

 

Note 14—Share-Based Awards

 

As of September 30, 2012, our 2006 Long-Term Incentive Plan (the “2006 Plan”) is our only authorized stock-based award plan. Our 2005 Stock Option Plan was terminated on March 11, 2011 as no options granted under the plan remained outstanding at that time. Our 2006 Plan authorizes the granting of incentive stock options, non-qualified stock options, stock appreciation rights, stock awards, restricted stock, restricted stock units and performance awards. A maximum of 4,000,000 shares are available for grant under this plan. The 2006 Plan is available to our employees and independent directors and is designed to attract and retain employees and independent directors, to further align the interests of our employees and independent directors with the interests of our stockholders, and to closely link compensation with our performance. The exercise price of stock options granted under this plan may not be less than the fair market value of the common stock on the date of grant. The options generally have a term of seven years and vest evenly over three years, except performance based awards which are granted solely to our named executive officers, and options issued to directors. Performance based awards granted under the 2006 Long-Term Incentive Plan vest once the performance criteria have been met. Options granted to our directors vest immediately.

 

During the three months ended September 30, 2012, we recorded compensation expense of $118,840 of which $7,475 was allocated to lease operating expenses and $111,365 was allocated to general and administrative expenses. During the nine months ended September 30, 2012, we recorded compensation expense of $532,989 of which $29,769 was allocated to lease operating expenses, $351,481was allocated to general and administrative expenses, $131,127 was allocated to restructuring costs, and $20,612 was capitalized to gas properties. The future compensation cost of all the outstanding awards at September 30, 2012 is $398,265 which will be amortized over the vesting period of such awards. The weighted average remaining useful life of the future compensation cost is 0.91 years.

 

During the three months ended September 30, 2011, we recorded compensation expense of $161,880 which was allocated as an addition of $6,593 to lease operating expense, an addition of $117,898 to general and administrative expense, and $37,389 was capitalized to gas properties. During the nine months ended September 30, 2011, we recorded compensation expense of $679,034 of which $26,756 was allocated to lease operating expense, $549,589 was allocated to general and administrative expenses, and $102,689 was capitalized to gas properties.

 

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On May 15, 2012, 150,000 shares of restricted stock were granted to our executive officers. The compensation cost was determined using NASDAQ’s closing price of our common stock on the day of issuance and is expensed ratably over the three-year vesting period.

 

On March 28, 2012, May 11, 2012, and August 10, 2012, 64,284, 97,824 and 300,000 shares of common stock, respectively, were issued under the 2006 Plan to our independent directors, each representing 12.5% of their annual retainer. The compensation cost was determined using NASDAQ’s closing price of our common stock on the day of issuance.

 

On April 5, 2011, we granted 673,551 stock options with time vesting criteria to certain key employees, including our five executive officers, 232,089 restricted stock units with performance vesting criteria to our five executive officers and 113,208 shares of common stock to our independent directors, representing 50% of their annual retainer. The significant assumptions used in determining the compensation costs included an expected volatility of 87.2%, risk-free interest rate of 2.28%, an expected term from 4.38 to 4.83 years, forfeiture rates from 5% to 15%, and no expected dividends.

 

Option Exchange

 

On December 7, 2010, we offered our eligible employees the opportunity to exchange certain outstanding stock options for new restricted shares of GeoMet common stock to be granted under the 2006 Plan (“Option Exchange”). Options eligible for exchange, or eligible options, included those options, whether vested or unvested, that met all of the following requirements:

 

·                  the options had a per share exercise price greater than $5.00;

 

·                  the options were granted under one of our existing equity incentive plans;

 

·                  the options were outstanding and unexercised as of January 5, 2010;

 

·                  the options were not granted within the twelve-month period immediately preceding the commencement of this offer, December 7, 2010; and

 

·                  the options did not have a remaining term of less than 12 months immediately following January 5, 2010.

 

On January 5, 2011, 98,416 shares of restricted stock were granted to those eligible employees as follows:

 

Exercise Price Per Share

 

Number of Eligible
Options

 

Number of New
Restricted Shares To
Be Granted in
Exchange

 

$

5.04

 

85,122

 

32,391

 

$

6.98

 

65,244

 

993

 

$

7.64

 

16,000

 

244

 

$

8.30

 

247,359

 

57,287

 

$

10.88

 

8,265

 

881

 

$

13.00

 

144,978

 

6,620

 

 

 

566,968

 

98,416

 

 

The Option Exchange was accounted for as a modification of an award in accordance with ASC 718-20-35-3. We recognize the incremental compensation expense of $102,348 over the remaining requisite service period. The incremental compensation expense is the excess of the fair value of the shares of restricted stock granted (using the closing market price) over the fair value of the cancelled options (using the black-scholes model) on January 5, 2011.

 

Incentive Stock Options

 

The table below summarizes incentive stock option activity for the nine months ended September 30, 2012:

 

 

 

Number of
Options

 

Weighted
Average
Exercise
Price

 

Average
Remaining
Contractual
Life

 

Aggregate
Intrinsic
Value

 

Outstanding at December 31, 2011

 

1,574,886

 

$

1.11

 

 

 

 

 

Forfeited

 

(152,048

)

$

1.05

 

 

 

 

 

Outstanding at September 30, 2012

 

1,422,838

 

$

1.11

 

4.4

 

$

 

Options exercisable at September 30, 2012

 

965,831

 

$

0.99

 

4.6

 

$

 

 

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Table of Contents

 

Non-Qualified Stock Options

 

The table below summarizes non-qualified stock option activity for the nine months ended September 30, 2012:

 

 

 

Number of
Options

 

Weighted
Average
Exercise
Price

 

Average
Remaining
Contractual
Life

 

Aggregate
Intrinsic
Value

 

Outstanding at December 31, 2011

 

992,272

 

$

2.32

 

 

 

 

 

Forfeited

 

(17,507

)

$

2.12

 

 

 

 

 

Outstanding at September 30, 2012

 

974,765

 

$

2.33

 

1.6

 

$

 

Options exercisable at September 30, 2012

 

933,242

 

$

2.40

 

1.5

 

$

 

 

Restricted Stock Awards

 

The table below summarizes non-vested restricted stock awards activity for the nine months ended September 30, 2012:

 

 

 

Number of
Shares

 

Weighted
Average Value at
Grant Date

 

Non-vested restricted stock at December 31, 2011

 

293,166

 

$

3.03

 

Granted

 

150,000

 

$

0.43

 

Vested

 

(159,978

)

$

3.00

 

Forfeited

 

(28,928

)

$

3.77

 

 

 

 

 

 

 

Non-vested restricted stock at September 30, 2012

 

254,260

 

$

1.43

 

 

During the three and nine months ended September 30, 2012, 21,363 shares and 159,978 shares of restricted stock, respectively, vested with a weighted average vesting date fair value of $0.16 and $0.55 per share, respectively.

 

Restricted Stock Unit Awards

 

On April 5, 2011, we granted 232,089 restricted stock units to our five executive officers. These restricted stock units vest upon the Company’s achievement of certain performance targets, but no earlier than ratably over the three year period following the grant date, at which time one common share will be issued and exchanged for each restricted stock unit held. The restricted stock units are included in the calculation of diluted earnings per share utilizing the treasury stock method. On April 30, 2012, 99,108 restricted stock units vested with a vesting date fair value of $0.53 per share. On June 25, 2012, 16,428 restricted stock units were forfeited. There have been no grants of restricted stock units subsequent to the aforementioned grant.

 

Note 15—Commitments and Contingencies

 

From time to time we are a party to litigation in the normal course of business. Management does not believe that the outcome of lawsuits or other proceedings against us will have an adverse effect on our financial condition, results of operations or cash flows.

 

Lease Revenue Audit—The lessor from one of our leases recently completed a five year revenue audit where the examiner claims to have identified an exception related to compressor fuel deductions. In May 2012, the claim was settled for $356,146, which was the amount recorded in the Consolidated Balance Sheet (Unaudited) as of March 31, 2012 and the Consolidated Statement of Operations (Unaudited) for the three months ended March 31, 2012 related to this matter.

 

Environmental and Regulatory

 

As of September 30, 2012, there were no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us.

 

Note 16—Income Taxes

 

We record our income taxes using an asset and liability approach in accordance with the provisions of ASC 740. This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities using enacted tax rates at the end of the period. Under ASC 740, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change.

 

For tax reporting purposes, we have federal and state net operating losses (“NOL’s”) of approximately $136.9 million and $141.3 million, respectively, at September 30, 2012 that are available to reduce future taxable income. For tax reporting purposes, we had federal and state NOL’s of approximately $126.0 million and $132.3 million, respectively, at December 31, 2011 that were available to reduce future taxable income. Our first material NOL carryforward expires in 2022 and the last one expires in 2031.

 

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Table of Contents

 

Additionally, for tax reporting purposes, we have a federal capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd., as described in Note 5—Discontinued Operations, of approximately $34.9 million at September 30, 2012 that is available to reduce future taxable capital gains and expiring in 2017.

 

At September 30, 2012, we have a valuation allowance of $93.9 million recorded against our net deferred tax asset which includes $80.8 million related to our U.S. operations and $13.3 million related to the capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd., as described in Note 5—Discontinued Operations.

 

The income tax expense for the nine months ended September 30, 2012 was different than the amount computed using the statutory rate primarily due to an $80.8 million valuation allowance on our deferred tax asset. A reconciliation of the effective tax rate to the statutory rate is as follows:

 

 

 

U.S.

 

 

 

Canada

 

 

 

Total

 

 

 

Amount computed using statutory rates

 

$

(33,039,717

)

34.00

%

$

(3,307

)

25.00

%

$

(33,043,024

)

34.00

%

State income taxes—net of federal benefit

 

(3,580,778

)

3.68

%

 

0.00

%

(3,580,778

)

3.68

%

Valuation Allowance

 

80,822,163

 

-83.17

%

3,307

 

-25.00

%

80,825,470

 

-83.16

%

Nondeductible items and other

 

(164,718

)

0.17

%

 

0.00

%

(164,718

)

0.17

%

Income tax provision

 

$

44,036,950

 

-45.32

%

$

 

0.00

%

$

44,036,950

 

-45.31

%

 

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Table of Contents

 

Item 2.                                  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Statement Regarding Forward-Looking Information

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations and other items in this Quarterly Report on Form 10-Q contain forward-looking statements and information that are based on management’s beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words “believe,” “anticipate,” “estimate,” “expect,” “intend,” “may,” “will,” “project,” “forecast,” “plan,” and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to certain risks, uncertainties and assumptions. Certain of these risks are summarized under “Item 1A. Risk Factors” in our 2011 Annual Report on Form 10-K that we filed with the SEC on March 30, 2012, which you should read carefully in connection with our forward-looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

 

You should read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in conjunction with the corresponding sections and our audited consolidated financial statements for the fiscal year ended December 31, 2011, which are included in our 2011 Annual Report on Form 10-K.

 

Overview

 

GeoMet, Inc. is primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”). We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator, developer and producer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the Cahaba and Black Warrior Basins in Alabama and the central Appalachian Basin in Virginia and West Virginia. We also own additional coalbed methane and oil and gas development rights, principally in Alabama, Virginia, and West Virginia. As of September 30, 2012, we own a total of approximately 157,000 net acres of coalbed methane and oil and gas development rights.

 

The natural gas industry is capital intensive. We have historically made substantial capital expenditures in the exploration for, development and acquisition of natural gas reserves. Our capital expenditures have been financed primarily with internally generated cash from operations and proceeds from bank borrowings. The continued availability of capital sources depends upon a number of variables, including proved reserves, production from existing wells, the sales prices for natural gas, the existence of hedging opportunities, our ability to acquire, locate and produce new reserves, and events occurring within the global capital markets.

 

Natural gas prices continue to adversely affect the natural gas industry and GeoMet in particular by reducing our cash flows, capital expenditures and debt capacity. During 2011 and the first five months of 2012, prices received for natural gas in the United States continued to decline significantly which we believe, among other things, was due to an over-supply of natural gas, primarily resulting from shale drilling and reduced demand due to a much warmer winter than normal. On April 21, 2012, the Henry Hub spot price closed at $1.825/ MMBtu, its lowest in over 10 years. Presented below are the NYMEX Settle Prices for the period January 2012 through November 2012 and the NYMEX Forward Curve Prices (as of November 2, 2012) for natural gas for the period December 2012 through December 2013.

 

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Table of Contents

 

 

Current Business Plan

 

Our current business plan is primarily focused around complying with our Fifth Amended and Restated Credit Agreement (the “Credit Agreement”), as amended, and reducing the borrowing base deficiency. In addition, we continue to focus on the reduction of costs and the optimization of production volumes to maintain maximum cash flow and liquidity in order to reduce the borrowings under our Credit Agreement.

 

The NASDAQ Capital Market

 

On May 10, 2012, we received approval from NASDAQ to transfer the listing of our common stock and preferred stock from The NASDAQ Global Market to The NASDAQ Capital Market. Our common stock and preferred stock began trading on The NASDAQ Capital Market at the opening of the market on May 14, 2012. On August 3, 2012, we received a notice from NASDAQ advising us that our common stock had failed to regain compliance with the $1.00 minimum bid price requirement for continued listing on The NASDAQ Capital Market and, as a result, our common stock was delisted from The NASDAQ Capital Market at the opening of business on August 13, 2012.  Our preferred stock continues to be traded on The NASDAQ Capital Market under the symbol “GMETP”. Our common stock now trades on the OTC Bulletin Board under the symbol “GMET”.

 

Other Developments

 

Management and Board of Director Changes

 

On April 30, 2012, J. Darby Seré resigned from the positions of Chairman of the Board, President and Chief Executive Officer of the Company. The Company and Mr. Seré entered into a separation agreement that provides for certain payments to Mr. Seré, including a lump sum payment of $499,500, $2,000 per month for 18 months and $30,000 per month as a consulting fee for up to nine months.  The separation agreement further provided for certain adjustments to equity awards owned by Mr. Seré.  The Board of Directors of the Company appointed Michael Y. McGovern as the Company’s Chairman of the Board; William C. Rankin, as a new Board member and as its new President and Chief Executive Officer; and Tony Oviedo, as the Company’s Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller. On July 2, 2012, Phil Malone resigned from his position on the Board of Directors in connection with his retirement from the Company.

 

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Table of Contents

 

Strategic Alternatives

 

In February 2012, the Company retained FBR Capital Markets & Co. (“FBR”) as its advisor to review strategic alternatives, primarily focused on identifying potential merger partners.  The Company continues to believe a merger transaction would be beneficial during the current natural gas price environment, allowing it to spread fixed costs over a larger production and reserve base. The Company will continue to pursue its long range plans pending identification of a suitable transaction. The initial retainer paid to FBR was $50,000 and there currently are no additional future financial commitments unless we enter into a transaction. The delisting of our common stock from The NASDAQ Capital Market may adversely impact our ability to execute on our strategic alternatives.  Although we have been active in our efforts to pursue a strategic alternative, these efforts have not yielded any results to date.  We have engaged in discussions with multiple parties and continue these efforts. Although we have targeted business combination opportunities where reserves and production are primarily natural gas, we have looked at other types of potential alternatives and remain open to all alternatives beneficial to shareholders, but can provide no assurances that such a transaction will be consummated.

 

Ceiling Write-Down

 

The ceiling test is calculated using the unweighted arithmetic average of the natural gas price on the first day of each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions, as allowed by the guidelines of the SEC. For the twelve months ended September 30, 2012, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $2.84 per Mcf, resulting in a natural gas price of $2.99 per Mcf when adjusted for regional price differentials. For the three and nine months ended September 30, 2012, we recorded a $25.4 million and $83.5 million write-down, respectively, of the carrying value of our U.S. full cost pool. We recorded a $15.8 million and $42.3 million write-down of the carrying value of our U.S. full cost pool at March 31, 2012 and June 30, 2012, respectively. Based on current forward natural gas price curve, we expect an additional ceiling write-down in the fourth quarter of 2012.

 

Operational Update

 

Our core areas of operations are in the Central Appalachian Basin of Virginia and West Virginia and the Black Warrior and Cahaba Basins in Alabama. The Central Appalachian Basin is a mountainous region where coal mining is prevalent. The Black Warrior and Cahaba Basins are hilly, gently rolling regions and coal mining is also present but less active. Current production in the Central Appalachian Basin is 26.4 MMcf per day. Current production in our Alabama properties is 10.9 MMcf per day.

 

On June 20, 2012, we sold Hudson’s Hope Gas, Ltd., which held our Canadian gas properties, in exchange for two million shares of Canada Energy Partners, Inc. which we are restricted from selling before June 20, 2013. In connection with the sale we recognized a non-cash loss of $0.7 million; however, this disposition will reduce our cash flow losses and future obligations such as plugging and abandonment.

 

Critical Accounting Policies

 

The preparation of financial statements in conformity with GAAP requires us to use our judgment to make estimates and assumptions that affect certain amounts reported in our financial statements. As additional information becomes available, these estimates and assumptions are subject to change and thus impact amounts reported in the future. Critical accounting policies are those accounting policies that involve judgment and uncertainties affecting the application of those policies and the likelihood that materially different amounts would be reported under different conditions or using differing assumptions. We periodically update our estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. There have been no significant changes to our critical accounting policies during the nine months ended September 30, 2012.

 

Natural Gas Production Operations Summary

 

The table below presents information on gas sales, net sales volumes, production expenses and per Mcf data for the three and nine months ended September 30, 2012 and 2011. This table should be read in conjunction with the discussion of the results of operations for the periods presented below (in thousands, except per Mcf amounts).

 

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Table of Contents

 

 

 

Three Months Ended
September  30,

 

Nine Months Ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Gas sales (1)

 

$

9,610

 

$

8,520

 

$

27,465

 

$

24,702

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

4,417

 

$

2,983

 

$

13,350

 

$

8,794

 

Compression and transportation expenses

 

2,218

 

1,082

 

6,758

 

2,959

 

Production taxes

 

442

 

390

 

1,276

 

1,078

 

 

 

 

 

 

 

 

 

 

 

Total production expenses

 

$

7,077

 

$

4,455

 

$

21,384

 

$

12,831

 

 

 

 

 

 

 

 

 

 

 

Net sales volumes (Consolidated) (MMcf)

 

3,391

 

1,940

 

10,468

 

5,619

 

Pond Creek field (Central Appalachian Basin) (MMcf)

 

1,462

 

1,439

 

4,402

 

4,148

 

Other Central Appalachian Basin fields (MMcf)

 

912

 

41

 

2,941

 

120

 

Gurnee field (Cahaba Basin) (MMcf)

 

430

 

453

 

1,325

 

1,330

 

Black Warrior Basin fields (MMcf)

 

587

 

3

 

1,800

 

9

 

 

 

 

 

 

 

 

 

 

 

Per Mcf data ($/Mcf):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average natural gas sales price realized (Consolidated)(2)

 

$

3.87

 

$

5.26

 

$

3.92

 

$

5.59

 

 

 

 

 

 

 

 

 

 

 

Average natural gas sales price (Consolidated)(3)

 

$

2.83

 

$

4.39

 

$

2.62

 

$

4.40

 

Pond Creek field (Central Appalachian Basin)

 

$

2.88

 

$

4.44

 

$

2.70

 

$

4.44

 

Other Central Appalachian Basin fields

 

$

2.69

 

$

4.23

 

$

2.48

 

$

4.28

 

Gurnee field (Cahaba Basin)

 

$

2.87

 

$

4.25

 

$

2.63

 

$

4.28

 

Black Warrior Basin fields

 

$

2.92

 

$

4.26

 

$

2.68

 

$

4.24

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses (Consolidated)

 

$

1.30

 

$

1.54

 

$

1.28

 

$

1.56