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, 2014

 

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)

 

1221 McKinney Street, Suite 3840

Houston, Texas 77010

(713) 659-3855

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

 

Former address:

909 Fannin, Suite 1850

Houston, Texas 77010

(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).  x  Yes o  No

 

As of November 1, 2014, 40,513,373 shares and 6,580,726 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, 2014 and December 31, 2013

3

 

 

Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013

4

 

 

Consolidated Statements of Comprehensive (Loss) Income for the three and nine months ended September 30, 2014 and 2013

5

 

 

Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013

6

 

 

Notes to Consolidated Financial Statements (Unaudited)

7

 

 

 

 

 

Item 2.

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

16

 

 

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

24

 

 

 

 

 

Item 4.

Controls and Procedures

24

 

 

 

 

Part II. Other Information

 

 

 

 

 

 

Item 1.

Legal Proceedings

24

 

 

 

 

 

Item 1A.

Risk Factors

24

 

 

 

 

 

Item 6.

Exhibits

25

 

2



Table of Contents

 

Part I. FINANCIAL INFORMATION

 

Item 1.                                   Financial Statements

 

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

 

 

September 30,
2014

 

December 31,
2013

 

ASSETS

 

 

 

 

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

$

24,118,090

 

$

8,108,272

 

Accounts receivable, net of allowance of $0 and $14,744 at September 30, 2014 and December 31, 2013, respectively

 

 

2,900,807

 

Other current assets

 

305,155

 

692,740

 

Total current assets

 

24,423,245

 

11,701,819

 

Natural gas properties— utilizing the full cost method of accounting:

 

 

 

 

 

Proved natural gas properties

 

 

333,109,974

 

Other property and equipment

 

 

3,158,701

 

Total property and equipment

 

 

336,268,675

 

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

 

 

(293,939,624

)

Property and equipment—net

 

 

42,329,051

 

Other noncurrent assets

 

10,832

 

769,384

 

TOTAL ASSETS

 

$

24,434,077

 

$

54,800,254

 

LIABILITIES, MEZZANINE AND STOCKHOLDERS’ DEFICIT

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

Accounts payable

 

$

403,525

 

$

3,541,770

 

Royalties payable

 

 

3,656,272

 

Accrued liabilities

 

13,187

 

1,073,653

 

Payable to purchaser of assets

 

346,606

 

 

Income tax payable

 

126,444

 

 

Derivative liability—natural gas contracts

 

 

834,151

 

Asset retirement obligations

 

173,524

 

265,470

 

Current portion of long-term debt

 

 

71,550,000

 

Total current liabilities

 

1,063,286

 

80,921,316

 

Asset retirement obligations

 

 

8,915,407

 

Derivative liability—natural gas contracts

 

 

709,571

 

Other long-term accrued liabilities

 

 

113,434

 

TOTAL LIABILITIES

 

1,063,286

 

90,659,728

 

Commitments and contingencies (Note 16)

 

 

 

 

 

Mezzanine equity:

 

 

 

 

 

Series A Convertible Redeemable Preferred Stock—net of offering costs of $1,660,435; redemption amount $63,813,590; $.001 par value; 7,401,832 shares authorized, 6,580,726 and 6,000,571 shares were issued and outstanding at September 30, 2014 and December 31, 2013, respectively

 

47,330,539

 

43,404,993

 

Stockholders’ Deficit:

 

 

 

 

 

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

 

 

 

Common stock, $0.001 par value—authorized 125,000,000 shares; 40,523,805 issued and 40,513,373 outstanding at September 30, 2014 and 40,662,749 issued and 40,652,317 outstanding at December 31, 2013

 

40,524

 

40,663

 

Treasury stock, at cost—10,432 shares at September 30, 2014 and December 31, 2013

 

(94,424

)

(94,424

)

Paid-in capital

 

183,621,322

 

187,527,716

 

Retained deficit

 

(207,527,170

)

(266,738,422

)

Total stockholders’ deficit

 

(23,959,748

)

(79,264,467

)

TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ DEFICIT

 

$

24,434,077

 

$

54,800,254

 

 

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,

 

 

 

2014

 

2013

 

2014

 

2013

 

Expenses:

 

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

$

 

$

32,212

 

$

113,817

 

$

101,223

 

General and administrative

 

1,212,887

 

1,049,372

 

3,160,010

 

3,456,126

 

Lease termination costs

 

 

 

427,722

 

 

Restructuring costs

 

 

6,000

 

 

93,584

 

Total operating expenses

 

1,212,887

 

1,087,584

 

3,701,549

 

3,650,933

 

 

 

 

 

 

 

 

 

 

 

Operating loss

 

(1,212,887

)

(1,087,584

)

(3,701,549

)

(3,650,933

)

 

 

 

 

 

 

 

 

 

 

Other income (expense)

 

2,457

 

(9,565

)

(17,746

)

(44,910

)

 

 

 

 

 

 

 

 

 

 

Loss before income taxes from continuing operations

 

(1,210,430

)

(1,097,149

)

(3,719,295

)

(3,695,843

)

 

 

 

 

 

 

 

 

 

 

Income tax expense

 

6,250

 

6,250

 

18,750

 

18,750

 

 

 

 

 

 

 

 

 

 

 

Loss from continuing operations

 

(1,216,680

)

(1,103,399

)

(3,738,045

)

(3,714,593

)

 

 

 

 

 

 

 

 

 

 

Discontinued operations, net of tax (benefit) expense of $(33,275) and $676,444 for the three and nine months ended September 30, 2014, respectively, and $0 for the three and nine months ended September 30, 2013

 

605,008

 

1,935,067

 

62,949,297

 

41,160,996

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

 

$

(611,672

)

$

831,668

 

$

59,211,252

 

$

37,446,403

 

Accretion of Series A Convertible Redeemable Preferred Stock

 

(772,910

)

(598,611

)

(2,122,819

)

(1,624,984

)

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

 

(649,937

)

(1,277,889

)

(1,802,727

)

(3,721,062

)

Cash dividends paid on Series A Convertible Redeemable Preferred Stock

 

(505

)

(634

)

(1,563

)

(1,835

)

Net (loss) income available to common stockholders

 

$

(2,035,024

)

$

(1,045,466

)

$

55,284,143

 

$

32,098,522

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share—basic:

 

 

 

 

 

 

 

 

 

Net loss per common share from continuing operations

 

$

(0.07

)

$

(0.07

)

$

(0.19

)

$

(0.22

)

Net income per common share from discontinued operations

 

0.02

 

0.04

 

1.55

 

1.01

 

Net (loss) income per common share—basic

 

$

(0.05

)

$

(0.03

)

$

1.36

 

$

0.79

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share— diluted:

 

 

 

 

 

 

 

 

 

Net loss per common share from continuing operations

 

$

(0.07

)

$

(0.07

)

$

(0.19

)

$

(0.22

)

Net income per common share from discontinued operations

 

0.02

 

0.04

 

1.55

 

1.01

 

Net (loss) income per common share— diluted

 

$

(0.05

)

$

(0.03

)

$

1.36

 

$

0.79

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares:

 

 

 

 

 

 

 

 

 

Basic

 

40,513,373

 

40,485,875

 

40,513,093

 

40,473,460

 

Diluted

 

40,513,373

 

40,485,875

 

40,513,093

 

40,473,460

 

 

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,

 

 

 

2014

 

2013

 

2014

 

2013

 

Net (loss) income

 

$

(611,672

)

$

831,668

 

$

59,211,252

 

$

37,446,403

 

Gain on foreign currency translation adjustment

 

 

45,198

 

 

36,080

 

Unrealized gain (loss) on available for sale securities

 

 

35,116

 

 

(5,293

)

 

 

 

 

 

 

 

 

 

 

Other comprehensive (loss) income

 

$

(611,672

)

$

911,982

 

$

59,211,252

 

$

37,477,190

 

 

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, 2014

 

Nine Months
Ended September
30, 2013

 

Cash flows (used in) provided by operating activities:

 

 

 

 

 

Loss from continuing operations

 

$

(3,738,045

)

$

(3,714,593

)

Adjustments to reconcile loss from continuing operations to net cash flows used in continuing operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

113,817

 

101,223

 

Stock-based compensation

 

20,575

 

188,209

 

Changes in operating assets and liabilities:

 

 

 

 

 

Other current assets

 

106,173

 

(30,950

)

Accounts payable

 

(296,676

)

(95,032

)

Other accrued liabilities

 

(168,057

)

(18,921

)

Net cash used in continuing operating activities

 

(3,962,213

)

(3,570,064

)

 

 

 

 

 

 

Income from discontinued operations

 

62,949,297

 

41,160,996

 

Adjustments to reconcile Income from discontinued operations to net cash flows (used in) provided by discontinued operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

715,892

 

3,645,707

 

Amortization of debt issuance costs

 

218,357

 

685,422

 

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

 

(1,543,722

)

1,574,208

 

Gain on the sale of gas properties

 

(62,395,740

)

(36,948,313

)

Loss on sale of other assets

 

22,706

 

53,366

 

Accretion expense

 

298,130

 

822,601

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

3,191,408

 

4,019,863

 

Other current assets

 

617,790

 

(388,622

)

Accounts payable

 

(6,333,495

)

(2,629,220

)

Income taxes payable

 

126,444

 

 

Other accrued liabilities

 

(1,638,773

)

(821,604

)

Net cash (used in) provided by discontinued operating activities

 

(3,771,706

)

11,174,404

 

 

 

 

 

 

 

Net cash (used in) provided by operating activities

 

(7,733,919

)

7,604,340

 

 

 

 

 

 

 

Cash flows provided by investing activities:

 

 

 

 

 

Continuing operations:

 

 

 

 

 

Proceeds from the sale of other assets

 

140,000

 

 

Net cash provided by investing activities- continuing operations

 

140,000

 

 

Discontinued operations:

 

 

 

 

 

Capital expenditures

 

(108,597

)

(580,323

)

Proceeds from the sale of gas properties

 

95,238,385

 

60,732,775

 

Proceeds from sale of other assets

 

25,511

 

19,276

 

Net cash provided by investing activities- discontinued operations

 

95,155,299

 

60,171,728

 

 

 

 

 

 

 

Net cash provided by investing activities

 

95,295,299

 

60,171,728

 

 

 

 

 

 

 

Cash flows used in financing activities:

 

 

 

 

 

Continuing operations:

 

 

 

 

 

Dividends paid

 

(1,562

)

(1,835

)

Treasury stock

 

 

(27

)

Net cash used in financing activities- continuing operations

 

(1,562

)

(1,862

)

Discontinued operations:

 

 

 

 

 

Repayment of borrowings under Credit Agreement

 

(71,550,000

)

(65,300,000

)

Deferred financing costs

 

 

(3,801

)

Net cash used in financing activities- discontinued operations

 

(71,550,000

)

(65,303,801

)

 

 

 

 

 

 

Net cash used in financing activities

 

(71,551,562

)

(65,305,663

)

 

 

 

 

 

 

Increase in cash and cash equivalents

 

16,009,818

 

2,470,405

 

Cash and cash equivalents at beginning of period

 

8,108,272

 

7,234,225

 

Cash and cash equivalents at end of period

 

$

24,118,090

 

$

9,704,630

 

 

 

 

 

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid during the period for:

 

 

 

 

 

Interest expense

 

$

1,448,385

 

$

4,169,622

 

Income taxes

 

$

18,750

 

$

18,750

 

 

 

 

 

 

 

Significant noncash investing and financing activities:

 

 

 

 

 

Accrued capital expenditures

 

$

 

$

30,380

 

 

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,” the “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the laws of the state of Delaware on November 9, 2000.

 

Prior to the completion of the sale of substantially all of our remaining assets on May 12, 2014, we were engaged in the exploration, development and production of natural gas from coal seams (“coalbed methane” or “CBM”). All of our production was CBM, which is a dry natural gas containing no hydrocarbon liquids. We were originally founded as a consulting company to the coalbed methane industry in 1985 and were active as an operator, developer and producer of coalbed methane properties since 1993. Our principal operations and producing properties were located in the central Appalachian Basin in Virginia and West Virginia.

 

From May 13, 2014 through August 15, 2014, we provided transition services to ARP Mountaineer Productions, LLC, purchaser of certain of our assets, while simultaneously working toward the completion of the final purchase price adjustment described in Note 3Sale of our Central Appalachian Assets and Termination of Credit Agreement. On August 15, 2014, we became a “shell company” as defined by Rule 12b-2 of the Securities Exchange Act of 1934, as amended, because we no longer had operations and our assets consisted of cash and nominal other assets.

 

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, 2013 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 31, 2014.

 

Note 2—Recent Accounting Pronouncement

 

In April 2014, the Financial Accounting Standards Board (“FASB”), issued Accounting Standards Update (“ASU”), No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The ASU changes the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when an entity meets the criteria to be classified as held for sale, the component of an entity or group of components of an entity is disposed of by sale, or the component of an entity or group of components of an entity is disposed of other than by sale. ASU 2014-08 should be applied when any of these occur within annual periods beginning on or after December 15, 2014. Early adoption is permitted; however, the Company elected not to early adopt the ASU. The ASU requires entities to separately present assets and liabilities of a discontinued operation for all periods presented in the balance sheet. The impact of adopting the ASU would be the reclassification of all of the assets related to our operations as Assets held for sale and all related liabilities as Liabilities held for sale, both in our Consolidated Balance Sheet (Unaudited) as of December 31, 2013.

 

In August 2014, the FASB issued ASU, No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The ASU provides guidance on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date of issuance of the entity’s financial statements (or within one year after the date on which the financial statements are available to be issued, when applicable). Further, an entity must provide certain disclosures if there is “substantial doubt about the entity’s ability to continue as a going concern.” The ASU is effective for annual periods ending after December 15, 2016, and interim periods thereafter and early adoption is permitted. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

 

7



Table of Contents

 

Note 3—Sale of our Central Appalachian Assets and Termination of Credit Agreement

 

On May 12, 2014, we closed the sale of substantially all of our remaining assets which consisted of coalbed methane interests and other assets located in the Appalachian Basin in McDowell, Harrison, Wyoming, Raleigh, Barbour and Taylor Counties, West Virginia and Buchanan County, Virginia (the “Asset Sale”) to ARP Mountaineer Productions, LLC, a Delaware limited liability company (the “Buyer”) and a wholly-owned subsidiary of Atlas Resource Partners, L.P., a Delaware limited partnership. The purchase price of $107.0 million was adjusted downward $10.0 million to account for purchase price adjustments, resulting in net proceeds of $97.0 million. We provided the final settlement statement to the Buyer on August 15, 2014. The proposed final purchase price adjustment provided to the Buyer was $346,606, which has been recorded as a current liability in the Consolidated Balance Sheet (Unaudited) as of September 30, 2014 and is expected to be settled in the fourth quarter of 2014.

 

Immediately following the closing of the Asset Sale, GeoMet, Bank of America, N.A., as administrative agent (the “Administrative Agent”), and the financial institutions party thereto terminated the Fifth Amended and Restated Credit Agreement, dated as of October 14, 2011, by and among GeoMet, the Administrative Agent, the financial institutions party thereto as lenders and the other agents party thereto (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). Immediately prior to termination of the Credit Agreement, we repaid all amounts owed to the lenders party to the Credit Agreement, which amounts totaled $69.1 million. As a result, we satisfied all of our obligations under the Credit Agreement. We were not required to pay a termination penalty or other fee in connection with the termination of the Credit Agreement.

 

Additionally, we settled all of our remaining outstanding natural gas hedge positions for approximately $3.1 million.

 

Note 4—Results of Discontinued Operations

 

As a result of the Asset Sale, all operating activities are presented as discontinued operations in the Consolidated Statements of Operations (Unaudited) for the three and nine months ended September 30, 2014 and 2013 as follows:

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Revenues:

 

 

 

 

 

 

 

 

 

Gas sales

 

$

 

$

7,391,747

 

$

13,645,825

 

$

30,324,181

 

Other

 

 

21,325

 

27,505

 

104,394

 

Total revenues

 

 

7,413,072

 

13,673,330

 

30,428,575

 

Expenses:

 

 

 

 

 

 

 

 

 

Lease operating expense

 

 

2,022,962

 

3,924,356

 

10,615,069

 

Compression and transportation expense

 

 

1,778,752

 

2,713,296

 

5,485,553

 

Production taxes

 

 

419,332

 

817,531

 

1,617,249

 

Lease termination costs

 

 

 

300,000

 

 

Depreciation, depletion and amortization

 

 

837,575

 

715,892

 

3,645,707

 

(Gains) losses on natural gas derivatives

 

 

(625,328

)

2,753,190

 

760,142

 

Total operating expenses

 

 

4,433,293

 

11,224,265

 

22,123,720

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on the sale of assets (1)

 

571,733

 

(187,298

)

62,395,740

 

36,948,313

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

571,733

 

2,792,481

 

64,844,805

 

45,253,168

 

 

 

 

 

 

 

 

 

 

 

Interest income

 

 

433

 

4,284

 

1,280

 

Interest expense

 

 

(857,847

)

(1,223,348

)

(4,093,452

)

Income tax benefit (expense)

 

33,275

 

 

(676,444

)

 

Income from discontinued operations

 

$

605,008

 

$

1,935,067

 

$

62,949,297

 

$

41,160,996

 

 


(1)                  The $571,733 gain on the sale of assets for the three months ended September 30, 2014 primarily resulted from the reduction of the asset retirement obligation through the assignment of certain wells to a third party.

 

Note 5— Gain on the Sale of Assets

 

The total gain on sale of assets for the three and nine months ended September 30, 2014 as presented above include the following:

 

 

 

Sale to ARP
Mountaineer
Productions, LLC

 

Other Sales

 

Total Gain

 

Cash proceeds

 

$

95,485,256

 

$

(246,871

)

$

95,238,385

 

Proposed final purchase price adjustment payable

 

(346,606

)

 

(346,606

)

Buyer’s assumption of asset retirement obligations

 

8,027,899

 

1,193,085

 

9,220,984

 

Buyer’s assumption of other liabilities

 

5,899,391

 

 

5,899,391

 

Net book value of sold gas properties

 

(41,332,191

)

 

(41,332,191

)

Net book value of sold equipment

 

(198,875

)

 

(198,875

)

Transaction costs

 

(6,085,348

)

 

(6,085,348

)

Total gain on sale

 

$

61,449,526

 

$

946,214

 

$

62,395,740

 

 

8



Table of Contents

 

Current year operating losses generated in the normal course of business are less than the estimated taxable gain from the Asset Sale.  However, no regular income tax is expected to result from the Asset Sale as we estimate sufficient net operating losses will be available from prior years to offset the estimated taxable gain, resulting in a reduction of our deferred tax asset and the related valuation allowance of $22.8 million. We are subject to a federal alternative minimum tax and have estimated that amount to be $676,444 for 2014. In September 2014, we made an estimated payment of $550,000 and $126,444 remains as a payable recorded in the Consolidated Balance Sheet (Unaudited) as of September 30, 2014.

 

Note 6— Pro Forma Financial Information

 

Pro forma adjustments related to the unaudited pro forma financial information presented below were computed assuming the asset sales completed in June 2013 and May 2014 were both consummated on January 1, 2013 and include adjustments which give effect to events that are (i) directly attributable to the asset sales, (ii) expected to have a continuing impact on the registrant, and (iii) factually supportable. As such, included in Net income (loss), Net income (loss) available to common stockholders and Net income (loss) per common share (basic and diluted) for the nine months ended September 30, 2013 are the gains on the asset sales completed in June 2013 and May 2014 of $36,948,313 and $62,395,740, respectively.

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Revenue

 

$

 

$

 

$

 

$

 

Loss from continuing operations

 

$

(1,216,680

)

$

(1,103,399

)

$

(3,738,045

)

$

(3,714,593

)

Net (loss) income

 

$

(1,249,955

)

$

(1,103,399

)

$

(3,771,320

)

$

95,629,460

 

Net (loss) income available to common stockholders

 

$

(2,673,307

)

$

(2,980,533

)

$

(7,698,429

)

$

90,281,579

 

Net (loss) income per common share—basic

 

$

(0.07

)

$

(0.07

)

$

(0.19

)

$

2.23

 

Net (loss) income per common share—diluted

 

$

(0.07

)

$

(0.07

)

$

(0.19

)

$

1.17

 

 

Note 7—Net (Loss) Income Per Common Share

 

Net income per common share—basic is calculated by dividing Net income available to common stockholders by the weighted average number of shares of Common Stock, par value $0.001 per share (the “Common Stock”) outstanding during the period. Net income per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net income available to common stockholders by the sum of the weighted average number of shares of Common Stock outstanding plus potentially dilutive securities. Net 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 shares of Common Stock would have an anti-dilutive effect. A reconciliation of Net (loss) income per common share for the three and nine months ended September 30, 2014 and 2013 is as follows:

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Net (loss) income

 

$

(611,672

)

$

831,668

 

$

59,211,252

 

$

37,446,403

 

Accretion of Series A Convertible Redeemable Preferred Stock

 

(772,910

)

(598,611

)

(2,122,819

)

(1,624,984

)

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

 

(649,937

)

(1,277,889

)

(1,802,727

)

(3,721,062

)

Cash dividends paid on Series A Convertible Redeemable Preferred Stock

 

(505

)

(634

)

(1,563

)

(1,835

)

Net (loss) income available to common stockholders —basic and diluted

 

$

(2,035,024

)

$

(1,045,466

)

$

55,284,143

 

$

32,098,522

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share—basic and diluted:

 

 

 

 

 

 

 

 

 

Net loss per common share from continuing operations

 

$

(0.07

)

$

(0.07

)

$

(0.19

)

$

(0.22

)

Net income per common share from discontinued operations

 

0.02

 

0.04

 

1.55

 

1.01

 

Net (loss) income per common share—basic and diluted

 

$

(0.05

)

$

(0.03

)

$

1.36

 

$

0.79

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares:

 

 

 

 

 

 

 

 

 

Basic and diluted

 

40,513,373

 

40,485,875

 

40,513,093

 

40,473,460

 

 

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Table of Contents

 

Net loss per common share—diluted for the three months ended September 30, 2014 excluded the effect of 6,383,526 weighted average shares of Series A Convertible Redeemable Preferred Stock, par value $0.001 per share (the “Preferred Stock “) (49,104,045 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance) because we reported Loss from continuing operations which caused the Preferred Stock to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the shares of Preferred Stock are anti-dilutive. As such, there was no add back to Net income available to common stockholders for the three months ended September 30, 2014 for accretion of and dividends paid for Preferred Stock of $772,910 and $649,897, respectively, in computing Net loss per common share—diluted as the shares of Preferred Stock were anti-dilutive.

 

Net income per common share—diluted for the nine months ended September 30, 2014 excluded the effect of 6,193,507 weighted average shares of Preferred Stock (47,642,363 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance), because we reported Loss from continuing operations which caused the options, restricted shares and the Preferred Stock to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the shares of Preferred Stock are anti-dilutive. As such, there was no add back to Net income available to common stockholders for the nine months ended September 30, 2014 for accretion of and dividends paid for Preferred Stock of $2,122,819 and $1,802,687, respectively, in computing Net income per common share—diluted as the shares of Preferred Stock were anti-dilutive.

 

Net loss per common share—diluted for the three months ended September 30, 2013 excluded the effect of outstanding options exercisable to purchase 1,591,920 shares, 116,553 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 176,935 weighted average restricted shares outstanding, and 5,644,456 weighted average shares of Preferred Stock (43,418,898 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance) because we reported Loss from continuing operations which caused the options, restricted shares and the Preferred Stock to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the shares of Preferred Stock are anti-dilutive. As such, there was no add back to Net income available to common stockholders for the three months ended September 30, 2013 for accretion of and dividends paid for Preferred Stock of $598,611 and $1,277,889, respectively, in computing Net loss per common share—diluted as the shares of Preferred Stock were anti-dilutive.

 

Net income per common share—diluted for the nine months ended September 30, 2013 excluded the effect of outstanding options exercisable to purchase 1,591,920 shares, 116,553 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 204,833 weighted average restricted shares outstanding, and 5,475,217 weighted average shares of Preferred Stock (42,117,057 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance) because we reported Loss from continuing operations which caused the options, restricted shares and the Preferred Stock to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the shares of Preferred Stock are anti-dilutive. As such, there was no add back to Net income available to common stockholders for the nine months ended September 30, 2013 for accretion of and dividends paid for Preferred Stock of $1,624,984 and $3,721,062, respectively, in computing Net income per common share—diluted as the shares of Preferred Stock were anti-dilutive.

 

Note 8—Gas Properties

 

As described in Note 3—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we sold substantially all of our remaining assets. Prior to the Asset Sale, the method of accounting for oil and gas producing activities determined which costs were capitalized and how these costs were ultimately matched with revenues and expenses. We used the full cost method of accounting for our gas properties. Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties were capitalized.

 

Gas properties were depleted using the units-of-production method. The depletion expense was 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.

 

10



Table of Contents

 

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 the 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’ 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. In addition, 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.

 

No ceiling test was performed at September 30, 2014, as there was no longer any value in the full cost pool. For the twelve months ended September 30, 2013, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.62 per Mcf, resulting in a natural gas price of $3.68 per Mcf when adjusted for regional price differentials. Based on the ceiling test performed utilizing the aforementioned prices, no write-down of the carrying value of our U.S. full cost pool was required at September 30, 2013.

 

Note 9—Asset Retirement Obligations

 

We record an asset retirement obligation (“ARO”) in 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 the abandonment obligation was incurred using an assumed cost of funds for GeoMet. Once the ARO is recorded, it is then accreted to its estimated future value using the same assumed cost of funds. Periodically, we update the cost assumptions resulting from market changes and revise the liability recorded accordingly.

 

The following table details the changes to our ARO for the nine months ended September 30, 2014:

 

Current portion of asset retirement obligation at January 1, 2014

 

$

265,470

 

Add: Long-term portion of asset retirement obligation at January 1, 2014

 

8,915,407

 

 

 

 

 

Asset retirement obligation at January 1, 2014

 

9,180,877

 

Conveyed to purchasers of assets

 

(9,220,983

)

Settlements

 

(78,711

)

Estimate revisions

 

(5,789

)

Accretion

 

298,130

 

 

 

 

 

Asset retirement obligation at September 30, 2014 (1)

 

173,524

 

Less: Current portion of asset retirement obligation

 

(173,524

)

 

 

 

 

Long-term portion of asset retirement obligation at September 30, 2014

 

$

 

 


(1)                  Consists of the estimated plugging and abandonment costs of our two remaining pinnate wells.

 

Note 10—Derivative Instruments and Hedging Activities

 

In connection with the closing of the Asset Sale described in Note 3—Sale of our Central Appalachian Assets and Termination of Credit Agreement, we settled all of our outstanding natural gas hedge positions for approximately $3.1 million.

 

Prior to the closing of the Asset Sale, in an effort to reduce the effects of the volatility of the price of natural gas on our operations, management had historically hedged 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 limited the downside risk of adverse price movements, it also limited future gains from favorable movements. We entered into hedging transactions, generally for forward periods up to two years or more, which increased the probability of achieving our targeted level of cash flows. Our price risk management policy strictly prohibited the use of derivatives for speculative positions.

 

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Table of Contents

 

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 incurred accounting losses on derivatives during periods where prices were rising and gains during periods where prices were falling which caused significant fluctuations in our Consolidated Balance Sheets (Unaudited) and Consolidated Statements of Operations (Unaudited).

 

Commodity Price Risk and Related Hedging Activities

 

At September 30, 2014, we had no natural gas derivative contracts.

 

At December 31, 2013, we had the following natural gas derivative contracts:

 

Contract
Type

 

Period

 

Volume
(MMBtu)

 

Fixed Price or
Sold Ceiling/

Bought Floor

 

Derivative
liability—
current

 

Derivative
liability—
non-current

 

Total Fair
Value of
Contract

 

Swap

 

January 2014 through March 2014

 

360,000

 

$ 3.82

 

$

(164,121

)

$

 

$

(164,121

)

Collar

 

January 2014 through December 2015

 

3,650,000

 

$ 4.30/$3.60

 

(280,392

)

(296,436

)

(576,828

)

Collar

 

January 2014 through December 2015

 

3,650,000

 

$ 4.20/$3.50

 

(389,638

)

(413,135

)

(802,773

)

 

 

 

 

7,660,000

 

 

 

$

(834,151

)

$

(709,571

)

$

(1,543,722

)

 

We reviewed the financial strength of our hedge counterparties and believed our credit risk was minimal. Our hedge counterparties were participants or affiliates of the participants in the Credit Agreement and the collateral for the outstanding borrowings under the Credit Agreement was used as collateral for our hedges. We did not have rights to collateral from our counterparties, nor did we have rights of offset against borrowings under the Credit Agreement.

 

We estimated 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. 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 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 were used to discount future cash flows. The estimated fair value of our natural gas derivative contracts also reflected its nonperformance risk, the risk that the obligation would not be fulfilled. Because nonperformance risk included our counterparties’ and our credit risk, we had considered the effect of credit risk on the fair value of our natural gas derivative contracts. 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 1-Year 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 1-Year Treasury bill rate.

 

We did not have any derivative assets or derivative liabilities as of September 30, 2014 and there were no transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three months ended September 30, 2014. Based on the use of observable market inputs, we had designated these types of instruments designated below as Level 2. The fair value of our Level 2 derivative instruments were as follows:

 

 

 

Asset Derivatives

 

Liability Derivatives

 

 

 

September 30, 2014

 

December 31, 2013

 

September 30, 2014

 

December 31, 2013

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas hedge positions

 

Derivative asset (current)

 

$

 

Derivative asset (current)

 

$

 

Derivative liability (current)

 

$

 

Derivative liability (current)

 

$

834,151

 

Natural gas hedge positions

 

Derivative asset (non- current)

 

 

Derivative asset (non- current)

 

 

Derivative liability (non- current)

 

 

Derivative liability (non-current)

 

709,571

 

Total derivatives not designated as hedging instruments

 

 

 

$

 

 

 

$

 

 

 

$

 

 

 

$

1,543,722

 

 

12



Table of Contents

 

The following losses on our hedging instruments have been classified as Discontinued operations on the Consolidated Statements of Operations (Unaudited) for the three and nine months ended September 30, 2014 and 2013.

 

 

 

 

 

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

 

 

 

Location of (Gain)

 

Three Months Ended

 

Nine Months Ended

 

 

 

or Loss Recognized in

 

September 30,

 

September 30,

 

Derivatives

 

Income on Derivatives

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

Natural gas collar/swap settled positions

 

Discontinued operations

 

$

 

$

(361,448

)

$

4,296,912

 

$

(814,066

)

Natural gas collar/swap unsettled positions

 

Discontinued operations

 

 

(263,880

)

(1,543,722

)

1,574,208

 

 

 

 

 

 

 

 

 

 

 

 

 

Total (gain) loss

 

 

 

$

 

$

(625,328

)

$

2,753,190

 

$

760,142

 

 

Note 11—Long-Term Debt

 

As described in Note 3—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we sold substantially all of our remaining assets. Immediately following the closing of the Asset Sale, we repaid all outstanding borrowings under the Credit Agreement of $69.1 million.

 

During 2012, the amounts borrowed under the Credit Agreement exceeded the borrowing base. Borrowings under the Credit Agreement at August 8, 2012 totaled $148.6 million. On August 8, 2012, in connection with the excess of borrowings over the borrowing base, we amended the Credit Agreement to provide for a tranche A loan in the amount of our borrowing base and a tranche B loan in the amount of the borrowing base deficiency.

 

On June 14, 2013, we closed the sale of all of our coalbed methane properties located in the state of Alabama. Simultaneously with the close of the property sale, approximately $57.0 million was used to repay outstanding borrowings under the Credit Agreement, which eliminated the borrowing base deficiency. After this repayment, borrowings outstanding under the Credit Agreement totaled $77.0 million.

 

For the three months ended September 30, 2014, we had no borrowings outstanding under the Credit Agreement. For the three months ended September 30, 2013, we had no borrowings and made payments of $3.0 million under the Credit Agreement. For the three months ended September 30, 2013, interest on the borrowings averaged 3.83% per annum.

 

For the nine months ended September 30, 2014, we had no borrowings and made payments of $71.6 million under the Credit Agreement. For the nine months ended September 30, 2013, we had no borrowings and made payments of $65.3 million under the Credit Agreement. For the period January 1, 2014 through May 12, 2014, interest on the borrowings averaged 5.00% per annum. For the nine months ended September 30, 2013, interest on the borrowings averaged 4.03% per annum.

 

The following is a summary of our long-term debt at September 30, 2014 and December 31, 2013:

 

 

 

September 30,
2014

 

December 31,
2013

 

 

 

 

 

 

 

Borrowings under the Credit Agreement

 

$

 

$

71,550,000

 

Less current maturities included in current liabilities

 

 

(71,550,000

)

 

 

 

 

 

 

Total long-term debt

 

$

 

$

 

 

We record our debt instruments based on contractual terms. We did not elect to apply the fair value option for recording financial assets and financial liabilities. 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. 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 as of December 31, 2013 was estimated to be approximately $70.1 million.

 

13



Table of Contents

 

Note 12—Income Taxes

 

We record our income taxes using an asset and liability approach. 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. 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 (“NOLs”) of approximately $118.2 million and $132.5 million, respectively, at September 30, 2014 that are available to reduce future taxable income. For tax reporting purposes, we had federal and state NOLs of approximately $156.0 million and $162.3 million, respectively, at December 31, 2013 that were available to reduce future taxable income. Our first material federal NOL carryforward expires in 2024 and the last one expires in 2033.

 

Additionally, for tax reporting purposes, we have a federal capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd. in 2012, of approximately $33.9 million at September 30, 2014 that is available to reduce future taxable capital gains and expires in 2017. Additionally, we have a federal capital loss carryforward of $0.2 million generated by the sale of other assets in 2014.

 

At September 30, 2014, we have a valuation allowance of $60.7 million recorded against our net deferred tax asset which includes $47.8 million related to our United States operations and $12.9 million related to the capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd. in 2012 and other assets in 2014.

 

A reconciliation of the effective tax rates to the statutory rate are as follows:

 

 

 

Three Months Ended
September 30, 2014

 

Nine Months Ended
September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

Amount computed using statutory rates

 

$

(217,158

)

34.00

%

$

20,368,191

 

34.00

%

State income taxes—net of federal benefit (1)

 

173,690

 

-27.19

%

2,240,064

 

3.74

%

Valuation Allowance (2)

 

(48,046

)

7.52

%

(22,755,547

)

-37.99

%

Stock-based compensation shortfall

 

 

%

636,443

 

1.06

%

Nondeductible items and other

 

64,489

 

-10.10

%

206,043

 

0.35

%

Income tax (benefit) expense

 

$

(27,025

)

-0.98

%

$

695,194

 

1.16

%

Income tax benefit (expense)—discontinued operations

 

33,275

 

 

 

(676,444

)

 

 

Income tax expense—continuing operations

 

$

6,250

 

 

 

$

18,750

 

 

 

 


(1)                  The income tax expense for the three months ended September 30, 2014 was different than the amount computed using the statutory rate primarily due to adjustments made to the current period expense related to the filing of our state income tax returns for the year ended December 31, 2013.

(2)                  The income tax expense for the nine months ended September 30, 2014 was different than the amount computed using the statutory rate primarily due to a decrease of $22.8 million in the valuation allowance on our deferred tax asset.

 

Current year operating losses generated in the normal course of business are less than the estimated taxable gain from the Asset Sale.  However, no regular income tax is expected to result from the Asset Sale as we estimate sufficient net operating losses will be available from prior years to offset the estimated taxable gain, resulting in a reduction of our deferred tax asset and the related valuation allowance of $22.8 million. We are subject to a federal alternative minimum tax and have estimated that amount to be $676,444 for 2014. In September 2014, we made an estimated payment of $550,000 and $126,444 remains as a payable recorded in the Consolidated Balance Sheet (Unaudited) as of September 30, 2014.

 

Note 13—Common Stock

 

As of September 30, 2014, shares of the Common Stock issued and outstanding were 40,523,805 and 40,513,373, respectively. As of December 31, 2013, shares of our Common Stock issued and outstanding were 40,662,749 and 40,652,317, respectively. Included in shares of our Common Stock issued as of September 30, 2014 and December 31, 2013 were 10,432 shares of treasury stock held by the Company. Included in our Common Stock both issued and outstanding at December 31, 2013 were 158,065 shares of restricted stock. During the nine months ended September 30, 2014, 153 shares of restricted stock were forfeited and canceled upon the termination of an employee by the Company, 2,724 shares of restricted stock expired unvested and were canceled, and 136,067 shares of restricted stock were cancelled in conjunction with the termination of the employment agreements with certain of our executive officers.

 

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Table of Contents

 

Note 14—Series A Convertible Redeemable Preferred Stock

 

At September 30, 2014 and December 31, 2013, 6,580,726 and 6,000,571 shares of Preferred Stock were issued and outstanding, respectively. At September 30, 2014, an additional 821,106 shares of the Preferred Stock were reserved exclusively for the payment of paid-in-kind dividends (“PIK dividends”). We measure the fair value of PIK dividends using the closing quoted NASDAQ market price on the dividend date (categorized as level 1). The following table details the activity related to the Preferred Stock for the three months ended September 30, 2014:

 

 

 

Dividend Period
(Three Months Ended)

 

Date Issued

 

Number of Shares

 

Balance

 

 

 

 

 

 

 

 

 

 

 

Balance at January 1, 2014

 

 

 

 

 

6,000,571

 

$

43,404,993

 

Accretion of discount on Preferred Stock

 

 

 

 

 

 

 

2,122,819

 

PIK Dividends Issued for Preferred Stock :

 

3/31/14

 

3/31/14

 

187,461

 

599,875

 

 

 

6/30/14

 

6/30/14

 

193,327

 

552,915

 

 

 

9/30/14

 

9/30/14

 

199,367

 

649,937

 

Balance at September 30, 2014

 

 

 

 

 

6,580,726

 

$

47,330,539

 

 

At September 30, 2014, the 6,580,726 shares of Preferred Stock were issued and outstanding were convertible into 50,620,969 shares of our Common Stock.

 

Note 15—Share-Based Awards

 

Our 2006 Long-Term Incentive Plan (the “2006 Plan”) authorized the granting of incentive stock options, non-qualified stock options, stock appreciation rights, stock awards, restricted stock, restricted stock units and performance awards. On May 12, 2014, all remaining awards under the 2006 Plan were forfeited and a $40,560 reduction in General and administrative expenses was recorded in the Consolidated Statements of Operations (Unaudited) resulting from forfeiture reversals.

 

Note 16— Commitments and Contingencies

 

From time to time we are a party to litigation in the normal course of business. While the outcome of lawsuits or other proceedings against us are not possible to reasonably predict, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.

 

Environmental and Regulatory

 

As of September 30, 2014, 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.

 

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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 in this report and under “Item 1A. Risk Factors” in our 2013 Annual Report on Form 10-K that we filed with the Securities and Exchange Commission (the “SEC”) on March 31, 2014, 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, 2013, which are included in our 2013 Annual Report on Form 10-K.

 

Overview

 

GeoMet, Inc. (“GeoMet,” the “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the laws of the state of Delaware on November 9, 2000.

 

Prior to the completion of the sale of substantially all of our remaining assets on May 12, 2014, we were engaged in the exploration, development and production of natural gas from coal seams (“coalbed methane” or “CBM”). All of our production was CBM, which is a dry natural gas containing no hydrocarbon liquids. We were originally founded as a consulting company to the coalbed methane industry in 1985 and were active as an operator, developer and producer of coalbed methane properties since 1993. Our principal operations and producing properties were located in the central Appalachian Basin in Virginia and West Virginia.

 

From May 13, 2014 through August 15, 2014, we provided transition services to ARP Mountaineer Productions, LLC, purchaser of certain of our assets, while simultaneously working toward the completion of the final purchase price adjustment described in Note 3Sale of our Central Appalachian Assets and Termination of Credit Agreement. On August 15, 2014, we became a “shell company” as defined by Rule 12b-2 of the Securities Exchange Act of 1934, as amended, because we no longer had operations and our assets consisted of cash and nominal other assets.

 

The natural gas industry is capital intensive. Natural gas markets traditionally have been highly volatile. We historically made substantial capital expenditures in the exploration, development and acquisition of natural gas reserves. Our capital expenditures had been financed primarily with internally generated cash flows from operations, bank borrowing and equity raises.

 

Business Plan

 

Subsequent to the sale of substantially all of our assets, completion of the related final purchase price adjustment and performance of the related transition services agreement, we focused our efforts towards (i) preserving cash by reducing overhead costs, (ii) maintaining compliance as a reporting company subject to the periodic and current reporting requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, (iii) winding down operatorship obligations and all remaining residual liabilities, and (iv) actively pursuing business combination/merger opportunities.  As of September 30, 2014, we reduced personnel to three paid employees, eliminated all employee benefits, terminated our office lease with respect to our office located at 909 Fannin Street, Suite 1850, Houston, Texas 77010 and moved to a smaller office space.  In addition, we are currently in negotiations with a third party to assign our working interest in and any future plugging and abandonment liability for our two remaining wells to such third party.  In our effort to pursue a business combination/merger, we are seeking a business combination or merger that will ultimately result in increasing shareholder value in the future, and have been involved in activities ranging from initial verbal discussions to the review of technical and financial data and other due diligence reviews with prospective candidates.  We believe that our position as a public “shell company” with cash reserves provides an incentive to private companies seeking a public company platform without being required to engage in an initial public offering. As of September 30, 2014, we have not identified any prospective candidates to engage with in a business combination/merger transaction and if we do not enter into a business combination/merger in the near future, we will proceed with a dissolution and distribution of our remaining assets in accordance with applicable law.

 

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Table of Contents

 

Recent Developments

 

Delisting of Preferred Stock

 

On September 23, 2014, the Company received a notification letter from the Listing Qualifications Staff (the “Staff”) of The NASDAQ Stock Market LLC (“NASDAQ”) advising the Company that the Staff believes that the Company is a “public shell” and that the continued listing of the Preferred Stock is no longer warranted.  The Staff believes that the Company no longer has an operating business and, as a result, purchasers of the Preferred Stock do not know definitely what the operating business of the Company will be in the future.  Therefore, in accordance with Nasdaq Listing Rule 5101, the Staff applied more stringent criteria for the continued listing of the Preferred Stock. After consideration of various factors that it considered relevant and significant, the Company determined that it would not take any action to appeal the Staff’s decision. Accordingly, the trading of the Preferred Stock was suspended at the opening of business on October 2, 2014 and the Preferred Stock was removed from listing and registration on NASDAQ. On October 27, 2014, NASDAQ notified the SEC of the delisting of the Preferred Stock on Form 25. The Preferred Stock is currently trading on the OTC Pink.

 

Asset Sale

 

On May 12, 2014, we closed the sale of substantially all of our remaining assets which consisted of coalbed methane interests and other assets located in the Appalachian Basin in McDowell, Harrison, Wyoming, Raleigh, Barbour and Taylor Counties, West Virginia and Buchanan County, Virginia (the “Asset Sale”) to ARP Mountaineer Productions, LLC, a Delaware limited liability company (the “Buyer”) and a wholly-owned subsidiary of Atlas Resource Partners, L.P., a Delaware limited partnership. The purchase price of $107.0 million was adjusted downward $10.0 million to account for purchase price adjustments, resulting in net proceeds of $97.0 million. We provided the final settlement statement to the Buyer on August 15, 2014. The proposed final purchase price adjustment provided to the Buyer was $346,606, which has been recorded as a current liability in the Consolidated Balance Sheet (Unaudited) as of September 30, 2014 and is expected to be settled in the fourth quarter of 2014.

 

Immediately following the closing of the Asset Sale, GeoMet, Bank of America, N.A., as administrative agent (the “Administrative Agent”), and the banks party thereto terminated the Fifth Amended and Restated Credit Agreement, dated as of October 14, 2011, by and among GeoMet, the Administrative Agent, the financial institutions party thereto as lenders and the other agents party thereto (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). Immediately prior to termination of the Credit Agreement, we repaid all amounts owed to the lenders party to the Credit Agreement, which amounts totaled approximately $69.1 million. As a result, we satisfied all of our obligations under the Credit Agreement. We were not required to pay a termination penalty or other fee in connection with the termination of the Credit Agreement.

 

Additionally, we settled all of our remaining outstanding natural gas hedge positions for approximately $3.1 million.

 

In connection with the Asset Sale, all of our employees who accepted employment with the Buyer following the consummation of the Asset Sale first resigned their employment with us. Our board of directors adopted a plan of termination effective as of the closing of the Asset Sale, pursuant to which we terminated all employment agreements existing at that time, change of control agreements and plans, and employee benefits, including those provided under our long-term incentive plan, and, in exchange for releases, paid approximately $4 million to such employees.

 

On August 31, 2014, all remaining employees were terminated with the exception of one paid named executive officers and two other employees, each of who remain employed on an at-will basis.

 

Areas of Operation

 

Prior to the closing of the Asset Sale, our core areas of operations were in the Central Appalachian Basin of Virginia and West Virginia. We also previously had operations located in the Black Warrior and Cahaba Basins in Alabama. On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in Alabama and, on May 12, 2014, closed the Asset Sale.

 

Central Appalachia

 

Pond Creek and Lasher Fields—We were the operator of 298 producing vertical CBM wells in which we owned a 99.0% average working interest in the Pond Creek and Lasher fields located in southern West Virginia and southwestern Virginia. Net daily sales of gas averaged 15.2 MMcf per day for the period January 1, 2014 through May 12, 2014. Our natural gas production from the Pond Creek field was delivered into the Jewell Ridge pipeline system owned by East Tennessee Natural Gas, LLC (“ETNG”). We had two long-term transportation agreements with ETNG which went into effect in April 2007 with total maximum daily quantities of 15,000 MMBtu’s and 10,000 MMBtu’s and primary terms of 15 years and 10 years, respectively. Our gas from the Lasher field was delivered into the Columbia Gas Transmission pipeline with firm transportation for 500 MMBtu’s per day. We also owned and operated a 12 mile, 8 inch high-pressure steel pipeline and gas treatment and compression facilities through which the Pond Creek field natural gas production was gathered, dehydrated, and compressed for delivery into the Jewell Ridge Lateral of the East Tennessee pipeline system. In addition, we owned and operated a disposal well to dispose of produced water from both the Pond Creek and Lasher fields.

 

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Table of Contents

 

Pinnate Horizontal Wells—We were the operator of 44 producing pinnate horizontal CBM wells in which we owned a 71.6% average working interest in central and northern West Virginia. We also had a 33.7 % average working interest in 67 non-operated pinnate horizontal wells in central West Virginia. Net daily sales of gas averaged 5.8 MMcf per day for the period January 1, 2014 through May 12, 2014. We were party to two firm transportation agreements with total maximum daily capacity of 18,500 MMBtu per day and primary terms expiring through November 2024 which could have been automatically extended at GeoMet’s option at the maximum tariff rate. We were also party to a 10,000 MMBtu per day gathering contract that was in a month-to-month evergreen term. In some cases, our natural gas sales volumes were delivered to market under transportation agreements controlled by our working interest partners. Generally, our natural gas sales volumes were sold at a delivery point into the respective interstate pipeline system utilized.

 

After selling substantially all of our remaining assets, we continue to pursue opportunities to divest our remaining non-core assets and their related plugging and abandonment liabilities. These non-core assets consist of 2 pinnate wells in West Virginia and, if we are not successful in divesting these non-core assets, we plan to perform the plugging and abandonment activities within the time required by state regulations or earlier if possible.

 

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 three months ended September 30, 2014.

 

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Table of Contents

 

Natural Gas Production Operations Summary

 

As a result of meeting all of the criteria established under GAAP, we have presented our natural gas operating results as discontinued operations in the Consolidated Statements of Operations (Unaudited) for the three and nine months ended September 30, 2014 and 2013 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, 2014 and 2013. 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).

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2014 (1)

 

2013

 

2014 (2)

 

2013

 

 

 

 

 

 

 

 

 

 

 

Gas sales

 

$

 

$

7,392

 

$

13,646

 

$

30,324

 

Lease operating expenses

 

$

 

$

2,023

 

$

3,924

 

$

10,615

 

Compression and transportation expenses

 

 

1,779

 

2,713

 

5,486

 

Production taxes

 

 

419

 

818

 

1,617

 

Total production expenses

 

$

 

$

4,221

 

$

7,455

 

$

17,718

 

 

 

 

 

 

 

 

 

 

 

Net sales volumes (Consolidated) (MMcf)

 

 

2,072

 

2,779

 

8,088

 

Pond Creek field (Central Appalachian Basin) (MMcf)

 

 

1,386

 

1,946

 

4,209

 

Other Central Appalachian Basin fields (MMcf)

 

 

686

 

833

 

2,224

 

Gurnee field (Cahaba Basin) (MMcf)

 

 

 

 

723

 

Black Warrior Basin fields (MMcf)

 

 

 

 

932

 

 

 

 

 

 

 

 

 

 

 

Per Mcf data ($/Mcf):

 

 

 

 

 

 

 

 

 

Average natural gas sales price (Consolidated)

 

$

 

$

3.57

 

$

4.91

 

$

3.75

 

Pond Creek field (Central Appalachian Basin)

 

$

 

$

3.60

 

$

5.01

 

$

3.78

 

Other Central Appalachian Basin fields

 

$

 

$

3.50

 

$

4.68

 

$

3.69

 

Gurnee field (Cahaba Basin)

 

$

 

$

 

$

 

$

3.77

 

Black Warrior Basin fields

 

$

 

$

 

$

 

$

3.73

 

Lease operating expenses (Consolidated)

 

$

 

$

0.98

 

$

1.41

 

$

1.31

 

Pond Creek field (Central Appalachian Basin)

 

$

 

$

1.07

 

$

1.29

 

$

1.12

 

Other Central Appalachian Basin fields

 

$

 

$

0.78

 

$

1.69

 

$

1.41

 

Gurnee field (Cahaba Basin)

 

$

 

$

 

$

 

$

2.84

 

Black Warrior Basin fields

 

$

 

$

 

$

 

$

0.74

 

Compression and transportation expenses (Consolidated)

 

$

 

$

0.86

 

$

0.98

 

$

0.68

 

Pond Creek field (Central Appalachian Basin)

 

$

 

$

0.75

 

$

0.66

 

$

0.66

 

Other Central Appalachian Basin fields

 

$

 

$

1.07

 

$

1.71

 

$

1.03

 

Gurnee field (Cahaba Basin)

 

$

 

$

 

$

 

$

0.29

 

Black Warrior Basin fields

 

$

 

$

 

$

 

$

0.18

 

Production taxes (Consolidated)

 

$

 

$

0.20

 

$

0.29

 

$

0.20

 

Pond Creek field (Central Appalachian Basin)

 

$

 

$

0.20

 

$

0.29

 

$

0.21

 

Other Central Appalachian Basin fields

 

$

 

$

0.21

 

$

0.31

 

$

0.19

 

Gurnee field (Cahaba Basin)

 

$

 

$

 

$

 

$

0.18

 

Black Warrior Basin fields

 

$

 

$

 

$

 

$

0.23

 

Total production expenses (Consolidated)

 

$

 

$

2.04

 

$

2.68

 

$

2.19

 

Pond Creek field (Central Appalachian Basin)

 

$

 

$

2.02

 

$

2.24

 

$

1.99

 

Other Central Appalachian Basin fields

 

$

 

$

2.06

 

$

3.71

 

$

2.63

 

Gurnee field (Cahaba Basin)

 

$

 

$

 

$

 

$

3.31

 

Black Warrior Basin fields

 

$

 

$

 

$

 

$

1.13

 

 


(1) Due to the Asset Sale completed on May 12, 2014, there are no results for the three months ended September 30, 2014.

(2) Presents information on gas revenues, sales volumes, production expenses and per Mcf data for the period from January 1, 2014 through the completion of the Asset Sale on May 12, 2014.

 

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Table of Contents

 

Results of Operations

 

Three months ended September 30, 2014 compared with three months ended September 30, 2013

 

The following are selected items derived from our Consolidated Statement of Operations (Unaudited) and their percentage changes from the comparable period are presented below.

 

 

 

Three Months Ended
September 30,

 

 

 

 

 

2014

 

2013

 

Change

 

 

 

(in thousands)

 

General and administrative

 

$

1,213

 

$

1,049

 

16

%

Discontinued operations, net of tax benefit of $33 and $0 for the three months ended September 30, 2014 and 2013, respectively

 

$

605

 

$

1,935

 

-69

%

Income tax expense

 

$

6

 

$

6

 

%

 

General and administrative. General and administrative expense increased by $0.2 million, or 16%, to $1.2 million compared to the prior year period. This increase primarily resulted from additional professional fees resulting from activities around corporate governance and the pursuit of a potential business combination/merger, offset by the reduction in employee expenses (primarily salaries and wages) resulting from the June 2013 sale of our Alabama assets and the May 2014 sale of substantially all of our remaining assets.

 

Discontinued operations, net of tax. Discontinued operations, net of tax decreased by $1.3 million, or 69%, to $0.6 million compared to the prior year quarter. This decrease primarily resulted from no operations in the current year quarter resulting from the May 2014 sale of substantially all of our remaining assets. Included in Discontinued operations, net of tax in the current year quarter was a $0.6 million gain primarily resulting from the sale of certain properties which had asset retirement obligations associated with them that were conveyed to the buyer. Included in Discontinued operations, net of tax in the prior year quarter was a $0.2 million loss resulting from the June 2013 sale of our Alabama assets.

 

Income tax expense. The income tax expense in the current year quarter was different than the amount computed using the statutory rate primarily due to adjustments made to the current quarter expense related to the filing of our state income tax returns for the year ended December 31, 2013. A reconciliation of the effective tax rate to the statutory rate is as follows:

 

Amount computed using statutory rates

 

$

(217,158

)

34.00

%

State income taxes—net of federal benefit

 

173,690

 

-27.19

%

Valuation Allowance

 

(48,046

)

7.52

%

Stock-based compensation shortfall

 

 

%

Nondeductible items and other

 

64,489

 

-10.10

%

Income tax (benefit) expense

 

$

(27,025

)

-0.98

%

Income tax benefit (expense)—discontinued operations

 

33,275

 

 

 

Income tax expense—continuing operations

 

$

6,250

 

 

 

 

Nine months ended September 30, 2014 compared with nine months ended September 30, 2013

 

The following are selected items derived from our Consolidated Statement of Operations (Unaudited) and their percentage changes from the comparable period are presented below.

 

 

 

Nine Months Ended
September 30,

 

 

 

 

 

2014

 

2013

 

Change

 

 

 

(in thousands)

 

General and administrative

 

$

3,160

 

$

3,456

 

-9

%

Lease termination costs

 

$

428

 

$

 

NM

%

Discontinued operations, net of tax of $676 and $0 for the nine months ended September 30, 2014 and 2013, respectively

 

$

62,949

 

$

41,161

 

53

%

Income tax expense

 

$

19

 

$

19

 

%

 

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Table of Contents

 

NM-Not Meaningful

 

General and administrative. General and administrative expense decreased by $0.3 million, or 9%, to $3.2 million compared to the prior year period. This decrease primarily resulted from the reduction in employee expenses (primarily salaries and wages) resulting from the June 2013 sale of our Alabama assets and the May 2014 sale of substantially all of our remaining assets, offset by additional professional fees resulting from activities around corporate governance and the pursuit of a potential business combination/merger.

 

Lease termination costs. Lease termination costs in the current year period resulted from the termination of our Houston office leases.

 

Discontinued operations, net of tax. Included in Discontinued operations, net of tax in the current year period was a $62.4 million gain resulting from the Asset Sale. Included in Discontinued operations, net of tax in the prior year period was a $36.9 million gain resulting from the June 2013 sale of our Alabama assets.

 

Income tax expense. The income tax expense in the current year period was different than the amount computed using the statutory rate primarily due to a $22.8 million reduction of the valuation allowance on our deferred tax asset. A reconciliation of the effective tax rate to the statutory rate for the nine months ended September 30, 2014 is as follows:

 

Amount computed using statutory rates

 

$

20,368,191

 

34.00

%

State income taxes—net of federal benefit

 

2,240,064

 

3.74

%

Valuation Allowance

 

(22,755,547

)

-37.99

%

Stock-based compensation shortfall

 

636,443

 

1.06

%

Nondeductible items and other

 

206,043

 

0.35

%

Income tax (benefit) expense

 

$

695,194

 

1.16

%

Income tax benefit (expense)—discontinued operations

 

(676,444

)

 

 

Income tax expense—continuing operations

 

$

18,750

 

 

 

 

Liquidity and Capital Resources

 

At September 30, 2014, our remaining balance of cash totaled approximately $24 million. These funds continue to be held by the Company and used for normal working capital and operating expense purposes while we evaluate our next steps. Cash flows used in operating activities for the nine months ended September 30, 2014 were $(7.7) million, as compared to $7.6 million provided by operating activities in the prior year period. The $15.3 million decrease was primarily due to reduced cash flows resulting from the June 2013 sale of our Alabama assets and the May 2014 sale of substantially all of our remaining assets. Proceeds from the sale of assets of $95.2 million were sufficient to repay all outstanding borrowing under the Credit Agreement of $69.1 million, as well as the $7.7 million used in operating activities for the nine months ended September 30, 2014. We believe we have adequate cash on hand to fund corporate activities for the next twelve months.

 

Closing of the Asset Sale

 

On May 12, 2014, we closed the Asset Sale. The purchase price of $107.0 million was adjusted downward $10.0 million to account for purchase price adjustments, resulting in net proceeds of $97.0 million. We provided the final settlement statement to the Buyer on August 15, 2014. The proposed final purchase price adjustment provided to the Buyer was $346,606, which has been recorded as a current liability in the Consolidated Balance Sheet (Unaudited) as of September 30, 2014 and is expected to be settled in the fourth quarter of 2014.

 

Immediately following the closing of the Asset Sale, GeoMet, Bank of America, N.A., as administrative agent (the “Administrative Agent”), and the banks party thereto terminated the Fifth Amended and Restated Credit Agreement, dated as of October 14, 2011, by and among GeoMet, the Administrative Agent, the financial institutions party thereto as lenders and the other agents party thereto (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). Immediately prior to termination of the Credit Agreement, we repaid all amounts owed to the lenders party to the Credit Agreement, which amounts totaled approximately $69.1 million. As a result, we satisfied all of our obligations under the Credit Agreement. We were not required to pay a termination penalty or other fee in connection with the termination of the Credit Agreement.

 

Additionally, we settled all of our remaining outstanding natural gas hedge positions for approximately $3.1 million.

 

In connection with the Asset Sale, all of our employees who accepted employment with the Buyer following the consummation of the Asset Sale first resigned their employment with us. Our board of directors adopted a plan of termination effective as of the closing of the Asset Sale, pursuant to which we terminated all employment agreements existing at that time, change of control agreements and plans, and employee benefits, including those provided under our long-term incentive plan, and, in exchange for releases, paid approximately $4 million to such employees.

 

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On August 31, 2014, all remaining employees were terminated with the exception of two named executive officers and two regular employees, each of who remain employed on an at-will basis.

 

The terms of our outstanding Preferred Stock provide that in the event of a liquidation or dissolution of the Company, the holders of the Preferred Stock would be entitled to a liquidation preference before the holders of the Common Stock, par value $0.001 (the “Common Stock”), would be entitled to receive any distributions from the Company. The liquidation preference is equal to the original investment amount of the Preferred Stock ($40 million) plus paid-in-kind shares plus accrued and unpaid dividends, and currently totals approximately $66 million. Therefore, if the Company was dissolved as of September 30, 2014, the estimated remaining cash of approximately $24 million would be less than the liquidation preference to which the holders of the Preferred Stock are currently entitled of $66 million. Absent a concession from the holders of the Preferred Stock, the holders of our Common Stock would not receive any distributions upon a dissolution of the Company.

 

It is not clear that the terms of our outstanding Preferred Stock would entitle the holders of the Preferred Stock to a liquidation preference in the event the Company was to engage in a business combination/merger.  If our outstanding Preferred Stock is not entitled to a liquidation preference in the event of a business combination/merger, then the holders of the Preferred Stock might instead exercise their rights to convert their shares into shares of Common Stock, and then participate with the holders of Common Stock in the proceeds of such transaction on an as-converted basis. As the estimated remaining cash as of September 30, 2014 is approximately $24 million, this would mean that the holders of the Preferred Stock would receive less in a business combination/merger than the holders of the Preferred Stock would receive in a dissolution as a result of their liquidation preference. In order for the Company to engage in a business combination/merger, the Company would have to receive the approval of the holders of at least fifty percent (50%) of the outstanding shares of Preferred Stock voting separately as a class, in addition to the approval of the holders of a majority of the outstanding shares of Common Stock including the outstanding shares of Preferred Stock voting on an as-converted basis treated as a single class.

 

The Company has been advised by the holders of more than fifty percent (50%) of the Preferred Stock that they will not vote in favor of a business combination/merger unless the terms of the transaction provide that the holders of the Preferred Stock will be entitled to receive at least the same value or distributions as such holders would have been entitled to receive in a dissolution pursuant to the liquidation preference to which the holders of the Preferred Stock are entitled. As a result, absent a concession from the holders of the Preferred Stock, it is likely that the holders of our Common Stock would not receive any distributions if the Asset Sale is followed by a business combination/merger.

 

Capital Expenditures

 

The following table is a summary of our capital expenditures on an accrual basis by category:

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Capital expenditures:

 

 

 

 

 

 

 

 

 

Leasehold acquisition

 

$

 

$

(8,127

)

$

99,876

 

$

102,766

 

Development

 

 

(223,139

)

(17,825

)

154,658

 

Asset retirement obligations

 

 

103,287

 

(5,790

)

51,779

 

Other items (primarily capitalized overhead)

 

 

 

 

10,006

 

Total capital expenditures

 

$

 

$

(127,979

)

$

76,261

 

$

319,209

 

 

Natural Gas Price Risk and Related Hedging Activities

 

Prior to the Asset Sale, in an effort to reduce the effects of the volatility of the price of natural gas on our operations, management had historically hedged 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 limited the downside risk of adverse price movements, it also limited future gains from favorable movements. We entered into hedging transactions, generally for forward periods up to two years or more, which increased the probability of achieving our targeted level of cash flows. Our price risk management policy strictly prohibited the use of derivatives for speculative positions.

 

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 incurred accounting losses on derivatives during periods where prices were rising and gains during periods where prices were falling which caused significant fluctuations in our Consolidated Balance Sheets (Unaudited) and Consolidated Statements of Operations (Unaudited).

 

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Simultaneously with the closing of the Asset Sale on May 12, 2014, we settled all of our remaining outstanding natural gas hedge positions for approximately $3.1 million. At September 30, 2014, we had no remaining natural gas collar positions.

 

Contractual Commitments

 

We had numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. As a result of the completion of the Asset Sale on May 12, 2014, all material commitments disclosed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Commitments” of our 2013 Annual Report on Form 10-K that we filed with the SEC on September 30, 2014 have been settled or conveyed to the Buyer.

 

Recent Pronouncements

 

In April 2014, the Financial Accounting Standards Board (“FASB”), issued Accounting Standards Update (“ASU”), No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The ASU changes the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when an entity meets the criteria to be classified as held for sale, the component of an entity or group of components of an entity is disposed of by sale, or the component of an entity or group of components of an entity is disposed of other than by sale. ASU 2014-08 should be applied when any of these occur within annual periods beginning on or after December 15, 2014. Early adoption is permitted; however, the Company elected not to early adopt the ASU. The ASU requires entities to separately present assets and liabilities of a discontinued operation for all periods presented in the balance sheet. The impact of adopting the ASU would be the reclassification of all of the assets included in the Asset Sale as Assets held for sale and all related liabilities as Liabilities held for sale, both in our Consolidated Balance Sheet (Unaudited) as of December 31, 2013.

 

In August 2014, the FASB issued ASU, No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The ASU provides guidance on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date of issuance of the entity’s financial statements (or within one year after the date on which the financial statements are available to be issued, when applicable). Further, an entity must provide certain disclosures if there is “substantial doubt about the entity’s ability to continue as a going concern.” The ASU is effective for annual periods ending after December 15, 2016, and interim periods thereafter and early adoption is permitted. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

 

Environmental Regulations

 

Prior to the closing of the Asset Sale, our exploration and production operations were subject to significant federal, state, and local environmental laws and regulations governing environmental protection as well as the discharge of substances into the environment. These laws and regulations may restrict the types, quantities, and concentrations of various substances that can be released into the environment as a result of natural gas drilling, production, and processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas or that impact protected species; require permits or other governmental authorization before commencing certain activities and require the installation of pollution control measures as a condition of such permits or authorizations; require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells; and restrict injection of liquids into subsurface strata that may contaminate groundwater. Governmental authorities have the power to enforce compliance with their laws, regulations and permits, and violations are subject to injunctive relief, as well as administrative, civil and even criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that are adopted in the future could have a material adverse impact on our operations.

 

We believe that we were in substantial compliance with existing applicable environmental laws and regulations. However, it is possible that new environmental laws or regulations or the modification of existing laws or regulations could have a material adverse effect on our operations. As a general matter, the recent trend in environmental legislation and regulation is toward stricter standards, and this trend will likely continue. To date, we have not been required to expend extraordinary resources in order to satisfy existing

 

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applicable environmental laws and regulations. However, costs to comply with existing and any new environmental laws and regulations could become material. Moreover, a serious incident of pollution may result in the suspension or cessation of operations in the affected area or in substantial liabilities to third parties. Although we maintain insurance coverage against costs of clean-up operations, no assurance can be given that we are fully insured against all such potential risks. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

 

Item 3.                                  Quantitative and Qualitative Disclosures About Market Risk

 

Commodity Price Risk. Prior to the closing of the Asset Sale, our major commodity price risk exposure was to the prices received for our natural gas production. Realized commodity prices received for our production were the spot prices applicable to natural gas. Prices received for natural gas were volatile and unpredictable and beyond our control. For the three months ended September 30, 2014, we had no natural gas sales. For the nine months ended September 30, 2014, a 10% decrease in the prices received for natural gas production would have decreased our gas revenues by approximately $1.36 million, which would have been offset by approximately $0.69 million by increased realized gas hedging gains.

 

Interest Rate Risk. On May 12, 2014, we repaid all outstanding borrowing under the Credit Agreement. Prior to the repayment, we had long-term debt subject to the risk of loss associated with movements in interest rates. All of the debt outstanding under the Credit Agreement accrued interest at floating or market rates. Fluctuations in market interest rates would have caused our interest costs to fluctuate. Based upon the weighted average balance outstanding under the Credit Agreement, a 1% increase in market interest rates would have increased interest expense and negatively impacted our cash flows for the nine months ended September 30, 2014 by approximately $0.17 million.

 

Item 4.         Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

In accordance with Securities Exchange Act of 1934, as amended (the “Exchange Act”) Rules 13a-15(e) and 15d-15(e), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2014 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

 

Changes in Internal Control Over Financial Reporting

 

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

Part II. OTHER INFORMATION

 

Item 1.                                   Legal Proceedings

 

From time to time we are a party to litigation in the normal course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.

 

Environmental and Regulatory

 

As of September 30, 2014, 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.

 

Item 1A.                         Risk Factors

 

There has been no changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2013.

 

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Item 6.                                  Exhibits

 

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

GeoMet, Inc.

 

 

 

 

 

Date: November 10, 2014

By

/S/ TONY OVIEDO

 

 

Tony Oviedo, Senior Vice President, Chief Financial Officer and Chief Accounting Officer (Principal Financial Officer)

 

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INDEX TO EXHIBITS

 

Exhibit
Number

 

Exhibits

 

 

 

3.1

 

Amended and Restated Certificate of Incorporation of GeoMet, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed on July 25, 2006 (Registration No. 333-131716)).

 

 

 

3.2

 

Certificate of Designations of Series A Convertible Redeemable Preferred Stock, par value $0.001 per share, of GeoMet, Inc. (incorporated herein by reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed on June 24, 2010).

 

 

 

3.3

 

Certificate of Amendment to the Certificate of Designations of Series A Convertible Redeemable Preferred Stock, par value $0.001 per share, of GeoMet, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K filed on December 28, 2010).

 

 

 

3.4

 

Amended and Restated Bylaws of GeoMet, Inc. (Adopted as of September 14, 2010) (incorporated herein by reference to Exhibit 3.1 of the Company’s Form 8-K filed on September 20, 2010).

 

 

 

3.5

 

Retention Bonus And Severance Agreement by and between Tony Oviedo and GeoMet, Inc. (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on August 27, 2014).

 

 

 

31.1*

 

Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

 

 

 

31.2*

 

Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

 

 

 

32*

 

Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

 

 

 

101*

 

Interactive Data Files.

 


*                   Filed herewith.

 

27