UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549


FORM 10-Q

 

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

 

For the quarterly period ended September 30, 2006


Commission file number 001-31539

 

ST. MARY LAND & EXPLORATION COMPANY

(Exact name of registrant as specified in its charter)

Delaware

 

41-0518430

(State or other jurisdiction

 

(I.R.S. Employer Identification No.)

of incorporation or organization)

 

 

 

1776 Lincoln Street, Suite 700, Denver, Colorado 80203
(Address of principal executive offices)                              (Zip Code)

(303) 861-8140
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer   x

 

Accelerated filer   o

 

Non-accelerated filer   o

 

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

As of October 23, 2006, the registrant had 54,876,768  shares of common stock, $0.01 par value, outstanding.

 




ST. MARY LAND & EXPLORATION COMPANY

INDEX

 

 

 

 

PAGE

 

Part I.

 

FINANCIAL INFORMATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Item 1.

 

Financial Statements (Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Balance Sheets September 30, 2006 and December 31, 2005

 

3

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Statements of Operations Three and Nine Months Ended September 30, 2006 and 2005

 

4

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Statements of Stockholders’ Equity and Comprehensive Income September 30, 2006 and December 31, 2005

 

5

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Statements of Cash Flows Nine Months Ended September 30, 2006 and 2005

 

6

 

 

 

 

 

 

 

 

 

 

 

 

 

Notes to Consolidated Financial Statements September 30, 2006

 

8

 

 

 

 

 

 

 

 

 

 

 

Item 2.

 

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

 

24

 

 

 

 

 

 

 

 

 

 

 

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk (included within the content of Item 2)

 

51

 

 

 

 

 

 

 

 

 

 

 

Item 4.

 

Controls and Procedures

 

51

 

 

 

 

 

 

 

 

 

Part II.

 

OTHER INFORMATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Item 1.

 

Legal Proceedings

 

51

 

 

 

 

 

 

 

 

 

 

 

Item 1A.

 

Risk Factors

 

51

 

 

 

 

 

 

 

 

 

 

 

Item 6.

 

Exhibits

 

52

 

 




PART I.   FINANCIAL INFORMATION

ITEM 1.   FINANCIAL STATEMENTS

ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except share amounts)

 

 

September 30,

 

December 31,

 

 

 

2006

 

2005

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

1,016

 

$

14,925

 

Short-term investments

 

1,450

 

1,475

 

Accounts receivable

 

134,388

 

165,197

 

Refundable income taxes

 

21,495

 

 

Prepaid expenses and other

 

22,331

 

7,283

 

Accrued derivative asset

 

48,425

 

6,799

 

Deferred income taxes

 

 

8,252

 

Total current assets

 

229,105

 

203,931

 

 

 

 

 

 

 

Property and equipment (successful efforts method), at cost:

 

 

 

 

 

Proved oil and gas properties

 

1,733,187

 

1,441,959

 

Less - accumulated depletion, depreciation, and amortization

 

(595,902

)

(497,621

)

Unproved oil and gas properties, net of impairment allowance of $9,798 in 2006 and $9,862 in 2005

 

49,623

 

44,383

 

Wells in progress

 

89,056

 

55,505

 

Other property and equipment, net of accumulated depreciation of $9,262 in 2006 and $8,046 in 2005

 

6,271

 

5,340

 

 

 

1,282,235

 

1,049,566

 

 

 

 

 

 

 

Noncurrent assets:

 

 

 

 

 

Goodwill

 

9,452

 

9,452

 

Long-term derivative asset

 

19,191

 

575

 

Other noncurrent assets

 

4,031

 

5,223

 

Total noncurrent assets

 

32,674

 

15,250

 

 

 

 

 

 

 

Total Assets

 

$

1,544,014

 

$

1,268,747

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued expenses

 

$

169,657

 

$

164,957

 

Accrued derivative liability

 

15,113

 

34,037

 

Deferred income taxes

 

17,625

 

 

Total current liabilities

 

202,395

 

198,994

 

 

 

 

 

 

 

Noncurrent liabilities:

 

 

 

 

 

Long-term credit facility

 

66,000

 

 

Convertible notes

 

99,956

 

99,885

 

Asset retirement obligation

 

71,208

 

66,078

 

Net Profits Plan liability

 

154,195

 

136,824

 

Deferred income taxes

 

203,837

 

128,296

 

Accrued derivative liability

 

54,206

 

64,137

 

Other noncurrent liabilities

 

5,803

 

5,213

 

Total noncurrent liabilities

 

655,205

 

500,433

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Common stock, $0.01 par value: authorized — 200,000,000 shares; issued: 55,120,282 shares in 2006 and 57,011,740 shares in 2005; outstanding, net of treasury shares: 54,870,282 shares in 2006 and 56,761,740 shares in 2005

 

551

 

570

 

Additional paid-in capital

 

34,367

 

123,278

 

Treasury stock, at cost: 250,000 shares in 2006 and 250,000 shares in 2005

 

(4,784

)

(5,148

)

Deferred stock-based compensation

 

 

(5,593

)

Retained earnings

 

651,693

 

510,812

 

Accumulated other comprehensive income (loss)

 

4,587

 

(54,599

)

Total stockholders’ equity

 

686,414

 

569,320

 

 

 

 

 

 

 

Total Liabilities and Stockholders’ Equity

 

$

1,544,014

 

$

1,268,747

 

 

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

3




ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)

 

 

 

For the Three Months

 

For the Nine Months

 

 

 

Ended September 30,

 

Ended September 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

Operating revenues:

 

 

 

 

 

 

 

 

 

Oil and gas production revenue

 

$

188,159

 

$

203,144

 

$

550,181

 

$

501,935

 

Oil and gas hedge gain (loss)

 

4,828

 

(8,441

)

14,808

 

(8,967

)

Marketed gas and other revenue

 

4,252

 

8,355

 

12,787

 

18,508

 

Gain on sale of proved properties

 

801

 

246

 

7,233

 

220

 

Total operating revenues

 

198,040

 

203,304

 

585,009

 

511,696

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Oil and gas production expense

 

44,998

 

38,071

 

129,490

 

100,418

 

Depletion, depreciation, amortization, and asset retirement obligation accretion

 

39,817

 

36,952

 

110,118

 

100,933

 

Exploration

 

9,766

 

10,692

 

35,872

 

27,474

 

Impairment of proved properties

 

5,259

 

 

6,548

 

 

Abandonment and impairment of unproved properties

 

920

 

817

 

3,368

 

4,506

 

General and administrative

 

9,725

 

9,772

 

30,940

 

23,239

 

Change in Net Profits Plan liability

 

(3,710

)

54,857

 

17,370

 

71,253

 

Marketed gas system and other operating expense

 

3,975

 

7,620

 

12,981

 

17,569

 

Unrealized derivative loss (gain)

 

68

 

(60

)

5,329

 

1,310

 

Total operating expenses

 

110,818

 

158,721

 

352,016

 

346,702

 

 

 

 

 

 

 

 

 

 

 

Income from operations

 

87,222

 

44,583

 

232,993

 

164,994

 

 

 

 

 

 

 

 

 

 

 

Nonoperating income (expense):

 

 

 

 

 

 

 

 

 

Interest income

 

90

 

83

 

1,454

 

263

 

Interest expense

 

(2,170

)

(2,344

)

(5,098

)

(6,562

)

 

 

 

 

 

 

 

 

 

 

Income before income taxes

 

85,142

 

42,322

 

229,349

 

158,695

 

Income tax expense

 

(29,265

)

(14,988

)

(82,866

)

(57,997

)

 

 

 

 

 

 

 

 

 

 

Net income

 

$

55,877

 

$

27,334

 

$

146,483

 

$

100,698

 

 

 

 

 

 

 

 

 

 

 

Basic weighted-average common shares outstanding

 

55,398

 

56,640

 

56,564

 

56,941

 

 

 

 

 

 

 

 

 

 

 

Diluted weighted-average common shares outstanding

 

64,926

 

66,738

 

66,332

 

66,847

 

 

 

 

 

 

 

 

 

 

 

Basic net income per common share

 

$

1.01

 

$

0.48

 

$

2.59

 

$

1.77

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per common share

 

$

0.88

 

$

0.42

 

$

2.25

 

$

1.55

 

 

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

4




 

ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (UNAUDITED)

(In thousands, except share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

Additional

 

 

 

 

 

Deferred

 

 

 

Other

 

Total

 

 

 

Common Stock

 

Paid-in

 

Treasury Stock

 

Stock-Based

 

Retained

 

Comprehensive

 

Stockholders’

 

 

 

Shares

 

Amount

 

Capital

 

Shares

 

Amount

 

Compensation

 

Earnings

 

Income (Loss)

 

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balances, December 31, 2004

 

57,458,246

 

$

574

 

$

127,374

 

(500,000

)

$

(5,295

)

$

(5,039

)

$

364,567

 

$

2,274

 

$

484,455

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income, net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

 

 

151,936

 

 

151,936

 

Change in derivative instrument fair value

 

 

 

 

 

 

 

 

(71,522

)

(71,522

)

Reclassification to earnings

 

 

 

 

 

 

 

 

14,366

 

14,366

 

Minimum pension liability adjustment

 

 

 

 

 

 

 

 

283

 

283

 

Total comprehensive income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

95,063

 

Cash dividends declared, $0.10 per share

 

 

 

 

 

 

 

(5,691

)

 

(5,691

)

Treasury stock purchases

 

 

 

 

(1,175,282

)

(28,902

)

 

 

 

(28,902

)

Retirement of treasury stock

 

(1,411,356

)

(14

)

(28,729

)

1,411,356

 

28,743

 

 

 

 

 

Issuance of common stock under Employee Stock Purchase Plan

 

28,447

 

 

601

 

 

 

 

 

 

601

 

Sale of common stock, including income tax benefit of stock option exercises

 

936,403

 

10

 

16,619

 

 

 

 

 

 

16,629

 

Deferred compensation related to issued restricted stock unit awards, net of forfeitures

 

 

 

3,404

 

 

 

(3,404

)

 

 

 

Directors’ stock compensation

 

 

 

 

13,926

 

306

 

(306

)

 

 

 

Accrued stock-based compensation

 

 

 

4,009

 

 

 

 

 

 

4,009

 

Amortization of deferred stock-based compensation

 

 

 

 

 

 

3,156

 

 

 

3,156

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balances, December 31, 2005

 

57,011,740

 

$

570

 

$

123,278

 

(250,000

)

$

(5,148

)

$

(5,593

)

$

510,812

 

$

(54,599

)

$

569,320

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income, net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

 

 

146,483

 

 

146,483

 

Change in derivative instrument fair value

 

 

 

 

 

 

 

 

68,644

 

68,644

 

Reclassification to earnings

 

 

 

 

 

 

 

 

(9,458

)

(9,458

)

Total comprehensive income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

205,669

 

Cash dividends declared, $0.10 per share

 

 

 

 

 

 

 

(5,602

)

 

(5,602

)

Treasury stock purchases

 

 

 

 

(3,319,300

)

(123,108

)

 

 

 

(123,108

)

Retirement of treasury stock

 

(3,275,689

)

(33

)

(122,598

)

3,275,689

 

122,631

 

 

 

 

 

Issuance of Directors’ shares from treasury

 

 

 

 

29,827

 

339

 

 

 

 

339

 

Issuance of common stock under Employee Stock Purchase Plan

 

12,918

 

 

404

 

 

 

 

 

 

404

 

Sale of common stock, including income tax benefit of stock option exercises

 

1,371,313

 

14

 

30,738

 

 

 

 

 

 

30,752

 

Adoption of Statement of Financial Accounting Standards No. 123R

 

 

 

(5,593

)

 

 

5,593

 

 

 

 

Stock-based compensation expense

 

 

 

8,138

 

13,784

 

502

 

 

 

 

8,640

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balances, September 30, 2006

 

55,120,282

 

$

551

 

$

34,367

 

(250,000

)

$

(4,784

)

$

 

$

651,693

 

$

4,587

 

$

686,414

 

 

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

5




 

ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

 

 

 

 

For the Nine Months

 

 

 

Ended September 30,

 

 

 

2006

 

2005

 

Reconciliation of net income to net cash provided by operating activities:

 

 

 

 

 

Net income

 

$

146,483

 

$

100,698

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Gain on sale of proved properties

 

(7,233

)

(220

)

Depletion, depreciation, amortization, and asset retirement obligation accretion

 

110,118

 

100,933

 

Exploratory dry hole expense

 

4,033

 

2,514

 

Abandonment and impairment of oil and gas properties

 

9,915

 

4,506

 

Unrealized derivative loss

 

5,329

 

1,310

 

Change in Net Profits Plan liability

 

17,370

 

71,253

 

Stock-based compensation expense

 

8,979

 

5,371

 

Deferred income taxes

 

64,612

 

9,485

 

Other

 

398

 

(38

)

Changes in current assets and liabilities:

 

 

 

 

 

Accounts receivable

 

30,810

 

(31,437

)

Refundable income taxes

 

(21,495

)

 

Prepaid expenses and other

 

(15,048

)

(2,540

)

Accounts payable and accrued expenses

 

(21,612

)

36,320

 

Income tax benefit from the exercise of stock options*

 

(15,110

)

3,991

 

Net cash provided by operating activities

 

317,549

 

302,146

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Proceeds from sale of oil and gas properties

 

1,183

 

1,211

 

Capital expenditures

 

(293,977

)

(204,835

)

Acquisition of oil and gas properties

 

(9,933

)

(73,440

)

Other

 

79

 

3,792

 

Net cash used in investing activities

 

(302,648

)

(273,272

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Proceeds from credit facility

 

338,000

 

234,307

 

Repayment of credit facility

 

(272,000

)

(220,000

)

Income tax benefit from the exercise of stock options*

 

15,110

 

 

Proceeds from sale of common stock

 

16,046

 

8,208

 

Repurchase of common stock

 

(123,108

)

(28,347

)

Dividends

 

(2,858

)

(2,863

)

Net cash used in financing activities

 

(28,810

)

(8,695

)

 

 

 

 

 

 

Net change in cash and cash equivalents

 

(13,909

)

20,179

 

Cash and cash equivalents at beginning of period

 

14,925

 

6,418

 

Cash and cash equivalents at end of period

 

$

1,016

 

$

26,597

 


*                    SFAS 123R requires presentation of the income tax benefit from the exercise of stock options to be presented in financing activites subsequent to adoption.  The prior period classification is to remain unchanged under SFAS 123R.

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

 

6




ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(continued)

 

Supplemental schedule of additional cash flow information and noncash investing and financing activities:

 

 

 

 

For the Nine Months

 

 

 

Ended September 30,

 

 

 

2006

 

2005

 

 

 

(in thousands)

 

 

 

 

 

 

 

Cash paid for interest, net of capitalized interest

 

$

8,157

 

$

7,998

 

 

 

 

 

 

 

Cash paid for income taxes

 

$

29,849

 

$

36,153

 

 

 

 

 

 

 

 

Dividends of approximately $2.7 million have been declared by the Company’s Board of Directors, but not paid, as of September 30, 2006.

Included in the accounts payable and accrued expenses account balances as of September 30, 2006, and 2005, are $90.5 million and $44.5 million, respectively, of additions to oil and gas properties.  These oil and gas property additions are reflected in cash used in investing activities in the periods that the payables are settled.

In February 2006 and March 2005 the Company issued 484,351 and 195,312 restricted stock units, respectively, pursuant to the Company’s restricted stock plan.  The total expenses associated with the issuances were $16.4 million and $4.5 million, respectively.

In May 2006, July 2006, and May 2005 the Company issued 26,076, 3,751, and 13,926 shares, respectively, of common stock from treasury to its non-employee directors.  The issuance in 2005 was pursuant to the Company’s non-employee director stock compensation plan and the 2006 issuances were pursuant to the Company’s 2006 equity incentive compensation plan.  The Company recorded compensation expense related to these issuances of $465,400 and $102,500 for the nine-month periods ended September 30, 2006 and 2005, respectively.

In May 2006 the Company closed a transaction whereby it exchanged non-core oil and gas properties located in the Uinta Basin for oil and gas properties located in Richland County, Montana.  This transaction is considered a non-monetary exchange for accounting purposes with a fair value assigned to this transaction of $11.5 million.

In June 2006 the Company hired a new senior executive.  In doing so, the Company issued 13,784 shares of stock and recorded compensation expense of approximately $737,000.  The new senior executive can earn up to 20,000 additional shares based on performance indicators.  Approximately $50,000 worth of expense has been recognized related to the additional shares.

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

7




ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

 


 

September 30, 2006

Note 1 — The Company and Business

St. Mary Land & Exploration Company (“St. Mary” or the “Company”) is an independent energy company engaged in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil.  The Company’s operations are conducted in the continental United States and offshore in the Gulf of Mexico.

Note 2 — Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of St. Mary have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information.  They do not include all information and notes required by generally accepted accounting principles for complete financial statements.  Except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in St. Mary’s Annual Report on Form 10-K for the year ended December 31, 2005.  In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation of the interim financial information have been included.  Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Other Significant Accounting Policies

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the Form 10-K for the year ended December 31, 2005, and are supplemented throughout the footnotes to the financial statements included in this document.  These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Form 10-K for the year ended December 31, 2005.

Note 3 Acquisitions

Richland County, Montana Acquisition

On May 15, 2006, the Company closed on a transaction whereby it exchanged non-core oil and gas properties located in the Uinta Basin for oil and gas properties located in Richland County, Montana. The transaction was structured as an Internal Revenue Code Section 1031 tax-deferred exchange. For financial reporting purposes, the transaction is considered a non-monetary exchange and has been accounted for at estimated fair value.  The exchange of properties resulted in recognition of a gain of approximately $7 million.  The final purchase accounting allocation and gain determination will be dependent on finalization of post-closing adjustments associated with revenue, expenses, and costs incurred between the effective date and the date of closing.  The Company expects that this allocation will be completed prior to the end of 2006.

8




Wold Acquisition

On August 1, 2005, the Company acquired oil and gas properties from Wold Oil Properties, Inc. (“Wold”) for $37.1 million in cash.  The Company allocated the purchase price based on the fair value of the acquired assets and liabilities.  The allocation of the purchase price resulted in recording $43.9 million to proved and unproved oil and gas properties, a $7.0 million asset retirement obligation, and a net $232,000 to other assets.

Agate Acquisition

On January 5, 2005, the Company acquired Agate Petroleum, Inc. (“Agate”) in exchange for $40.0 million in cash.  The Company allocated the purchase price based on the estimated fair value of the acquired assets and liabilities.  The Company acquired $4.6 million in cash from Agate, and the allocation of the purchase price resulted in recording $41.9 million to proved and unproved oil and gas properties, $1.1 million to net current liabilities, $9.5 million to goodwill, a deferred income tax liability of $13.5 million, and a $1.4 million asset retirement obligation.

Note 4 — Earnings per Share

Basic net income per common share of stock is calculated by dividing net income available to common stockholders by the weighted-average basic common shares outstanding during each period.  The shares represented by vested restricted stock units are included in the calculation of the weighted-average basic common shares outstanding.  The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.

Diluted net income per common share of stock is calculated by dividing adjusted net income by the weighted-average of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Adjusted net income is used for the if-converted method and is derived by adding interest expense paid on the Company’s 5.75% Senior Convertible Notes due 2022 (the “Convertible Notes”) back to net income and then adjusting for non-discretionary items that are based on income and that would have changed had the Convertible Notes been converted at the beginning of the period.  Potentially dilutive securities of the Company consist of in-the-money outstanding options to purchase the Company’s common stock, shares into which the Convertible Notes may be converted, and unvested restricted stock units.

The shares underlying the grants of restricted stock units are included in the diluted earnings per share calculation beginning with the grant date of units regardless of whether the shares are vested or unvested.   Following the lapse of the restriction period, the shares underlying the units will be issued and thereby included in the number of issued and outstanding shares.

The dilutive effects of stock options and unvested restricted stock units are considered in the detailed calculation below.  There were no anti-dilutive securities related to stock options or restricted stock units for any periods presented.

Shares associated with the conversion feature of the Convertible Notes are accounted for using the if-converted method as described above and are considered in the detailed calculation below.  A total of 7,692,307 potentially dilutive shares related to the Convertible Notes were included in the calculation of diluted net income per common share for the three-month and nine-month periods ended September 30, 2006, and 2005.  The Convertible Notes were issued in March 2002 and can be called by the Company in March 2007.

Prior to the adoption of Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (“SFAS No. 123R”) on January 1, 2006, the Company accounted for share-based awards under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, “Accounting

9




for Stock Issued to Employees” (“ABP Opinion No. 25”) and related interpretations.  Under this method no compensation cost was reflected in net income for issued stock options as all stock options had an exercise price equal to the market value of the underlying common stock on the date of grant.  Therefore, in calculating potential diluted common shares for purposes of EPS the amount of compensation cost for stock options measured was not included in the calculation since no expense had been recognized by the Company for stock options.

Effective January 1, 2006, the Company adopted SFAS No. 123R using the modified-prospective transition method. Under that transition method prospective compensation expense includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R.  Therefore, in calculating assumed proceeds and potential common shares for purposes of EPS, the Company began including the unrecognized compensation expense for stock options as of January 1, 2006, based on the grant date fair value.

The following table sets forth the calculation of basic and diluted earnings per share:

 

 

 

For the Three Months

Ended September 30,

 

For the Nine Months

Ended September 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

 

 

(In thousands, except per share amounts)

 

Net income

 

$

55,877

 

$

27,334

 

$

146,483

 

$

100,698

 

 

 

 

 

 

 

 

 

 

 

Adjustments to net income for dilution:

 

 

 

 

 

 

 

 

 

Add: interest expense not incurred if Convertible Notes converted

 

1,597

 

1,597

 

4,740

 

4,740

 

Less: other adjustments

 

(16

)

(16

)

(47

)

(47

)

Less: income tax effect of adjustment items

 

(543

)

(564

)

(1,696

)

(1,715

)

Net income adjusted for the effect of dilution

 

$

56,915

 

$

28,351

 

$

149,480

 

$

103,676

 

 

 

 

 

 

 

 

 

 

 

Basic weighted-average common shares outstanding

 

55,398

 

56,640

 

56,564

 

56,941

 

Add: dilutive effects of stock options and unvested restricted stock units

 

1,836

 

2,406

 

2,076

 

2,214

 

Add: dilutive effect of Convertible Notes using if-converted method

 

7,692

 

7,692

 

7,692

 

7,692

 

Diluted weighted-average common shares outstanding

 

64,926

 

66,738

 

66,332

 

66,847

 

Basic earnings per common share

 

$

1.01

 

$

0.48

 

$

2.59

 

$

1.77

 

Diluted earnings per common share

 

$

0.88

 

$

0.42

 

$

2.25

 

$

1.55

 

Note 5 — Compensation Plans

Cash Bonus Plan

The Company has a cash bonus plan that allows participants to receive a cash bonus of up to 50 percent of their aggregate base salary.  Any awards under the cash bonus plan are based on a combination of Company and individual performance.  The Company accrues cash bonus expense related to the current year’s performance.  The cash bonus expenses for the three-month periods ended September 30, 2006, and 2005, were $687,000 and $3.2 million, respectively, and the cash bonus expenses for the nine-month

10




periods ended September 30, 2006, and 2005, were $3.4 million and $4.8 million, respectively.  Cash bonuses related to the 2006 performance year are expected to be paid in the first quarter of the subsequent year.

Net Profits Plan

Under the Company’s Net Profits Interest Bonus Plan (the “Net Profits Plan”), oil and gas wells that are completed or acquired during a year are designated within a specific pool.  Key employees recommended by senior management and designated as participants by the Company’s Compensation Committee of the Board of Directors and employed by the Company on the last day of that year become entitled to bonus payments after the Company has received net cash flows returning 100 percent of all costs associated with that pool.  Thereafter, ten percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually.  The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the ten percent level.  The Net Profits Plan has been in place since 1991.  Pool years prior to and including 2005 are fully vested.  Pool years beginning in 2006 will carry a vesting period of three years, whereby one-third is vested at the end of the year for which participation is designated and one-third vests each of the following two anniversary dates.  Beginning with the 2006 pool, the maximum benefit to full participants from a particular year’s pool will be limited to 300 percent of a participating individual’s salary paid during the year to which the pool relates.

In a separate calculation, the Company records the estimated liability for future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool.  The calculation of this liability is a significant management estimate.  For a predominate number of the pools, a discount rate of 15 percent is used to calculate this liability and is intended to represent the best estimate of the present value of expected future payments under the Net Profits Plan.  The Company’s estimate of its liability is highly dependent on the price assumptions and discount rates used in the calculations.  The commodity price assumptions are currently formulated by applying a price that is derived from a rolling average of actual prices realized over the prior 24 months together with adjusted New York Mercantile Exchange, Inc., (“NYMEX”) strip prices for the ensuing 12 months for a total of 36 months of data. This average is supplemented by including the effect of hedge prices for the percentage of forecasted production hedged in the relevant period.  The forecasted expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the oil and natural gas commodity markets.  Higher commodity prices experienced in recent years have moved more pools into payout status.  The Company continually evaluates the assumptions used in this calculation in order to include the current market environment for oil and gas prices, discount rates, and overall market conditions.

11




The following table presents the changes in the estimated future liability attributable to the Net Profits Plan.  These amounts relate to the realized results for the periods presented from oil and gas operations for the properties associated with the respective pools that have achieved payout status.

 

 

For the Three Months

Ended September 30,

 

For the Nine Months

Ended September 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

 

 

(In thousands)

 

(In thousands)

 

Liability balance for Net Profits Plan as of the beginning of the period

 

$

157,904

 

$

46,957

 

$

136,824

 

$

30,561

 

Increase in liability

 

3,043

 

60,988

 

37,937

 

84,952

 

Reduction in liability for cash payments made or accrued and recognized as compensation expense

 

(6,752

)

(6,131

)

(20,566

)

(13,699

)

Liability balance for Net Profits Plan as of the end of the period

 

$

154,195

 

$

101,814

 

$

154,195

 

$

101,814

 

The calculation of the estimated liability for the Net Profits Plan is highly sensitive to price estimates and discount rate assumptions.  For example, if the commodity prices in the calculation were changed by ten percent, the liability recorded at September 30, 2006, would differ by approximately $32 million.  A one percentage point change in the discount rate would result in a change of approximately $7 million. Actual cash payments to be made in future periods are dependent on realized actual production, prices, and costs associated with the properties in each individual pool of the Net Profits Plan.  Consequently, actual cash payments will be inherently different from the amounts estimated.

The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate item in the consolidated statements of operations.  The change in the estimated liability is recorded as an expense or benefit in the current period.  The amount recorded associated with the change in the estimated liability is not allocated to general and administrative costs or exploration costs because it is an estimate at the current time of the adjustment to the liability that is associated with the future net cash flows from oil and gas properties in the respective pools rather than current period realized performance.  The table below presents the estimated allocation of the change in the liability if the Company did allocate the adjustment to these specific line items:

 

 

 

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

 

 

(In thousands)

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

General and administrative expense

 

$

(1,627

)

$

26,758

 

$

7,337

 

$

34,889

 

Exploration expense

 

(2,083

)

28,099

 

10,033

 

36,364

 

Total

 

$

(3,710

)

$

54,857

 

$

17,370

 

$

71,253

 

Equity Incentive Compensation Plan

There are several components to the equity compensation plan that are described in this section.  The various types of grants are a result of when the equity awards were granted by the Company.  For example, the Company ceased issuing stock options in 2004 and began issuing restricted stock or restricted stock units to employees.  The disclosures reflect the culmination of the disclosure requirements for all equity awards still outstanding.

12




In May 2006, the stockholders approved the 2006 Equity Incentive Compensation Plan (the “2006 Plan”) to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, and stock-based awards to key employees, consultants, and members of the Board of Directors of St. Mary or any affiliate of St. Mary.  The 2006 Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the St. Mary Land & Exploration Company Restricted Stock Plan, and the St. Mary Land & Exploration Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”).  All grants of equity are now made out of the 2006 Plan, and no further grants will be made under the Predecessor Plans.  Each outstanding award under a Predecessor Plan immediately prior to the effective date of the 2006 Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances.

Effective January 1, 2006, the Company adopted SFAS 123R using the modified-prospective transition method. Under that transition method, compensation expense recognized in the nine months ended September 30, 2006, includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R.

As of September 30, 2006, 2.6 million shares of common stock remained available for grant under the 2006 Plan.  Any issuance of a direct share benefit such as an outright grant of common stock, a grant of a restricted share or a restricted stock unit counts as two shares for each share issued against the amount eligible to be granted under the 2006 Plan.  Each stock option and similar instrument granted counts as one share for each share issued against the eligible shares authorized to be issued under the 2006 Plan.

St. Mary anticipates granting restricted stock and restricted stock units under the 2006 Plan for the foreseeable future.  However, the Company does have outstanding stock option grants under the Predecessor Plans.  The following sections describe the details of restricted stock units and stock options outstanding as of September 30, 2006.

Restricted Stock Incentive Program Under the Equity Incentive Compensation Plan

The Company has a long-term incentive program whereby grants of restricted stock or restricted stock units (“RSUs”) have been awarded to eligible employees, consultants, and members of the Board of Directors.  Restrictions and vesting periods for the awards are determined at the discretion of the Board of Directors and are set forth in the award agreements.  Each RSU represents a right for one share of the Company’s common stock to be delivered upon settlement of the award at the end of a specified period.  These grants are determined annually based on a formula consistent with the cash bonus plan.

St. Mary issued  484,351 RSUs on February 28, 2006, related to 2005 performance and 195,312 RSUs on March 15, 2005, related to 2004 performance.  The total fair value associated with these issuances was $16.4 million in 2006 and $4.5 million in 2005 as measured on the respective grant dates.  The granted RSUs vest 25 percent immediately upon grant and 25 percent on each of the next three anniversary dates of the grant.  Compensation expense is recorded monthly over the vesting period of the award.  The vested shares underlying the RSU grants will be issued on the third anniversary of the grant, at which time the shares carry no further restrictions.  As of September 30, 2006, there was a total of 1,072,152 RSUs outstanding, of which 552,562 were vested.  Total compensation expense related to the RSUs for the three-month periods ended September 30, 2006, and 2005, was $1.6 million and $3.0 million, respectively, and total compensation expense related to the RSUs for the nine-month periods ended September 30, 2006, and 2005, was $6.9 million and $5.3 million, respectively.  The 2006

13




period includes $1.2 million of compensation expense for the estimated value of grants expected to be issued in 2007 related to the 2006 performance year.

Stock Awards Under the Equity Incentive Compensation Plan

As part of hiring a new senior executive in the second quarter of 2006, St. Mary granted a special common stock award of 20,000 shares which vested immediately upon commencement of employment.  Approximately $728,000 of compensation expense was recorded related to this award.  In addition to this award, the employee may earn an additional 20,000 shares contingent on the Company meeting certain performance conditions.  The fair value of this award will be recorded to compensation expense over the vesting period.  As of September 30, 2006, approximately $50,000 of compensation expense had been recorded related to the contingent award.

A summary of the status and activity of non-vested RSUs for the nine-month period ended September 30, 2006, is presented below. 

 

 

 

 

Weighted-

 

 

 

 

 

Average

 

 

 

 

 

Grant-Date

 

 

 

Shares

 

Fair Value

 

Non-vested, at December 31, 2005

 

356,099

 

$

18.91

 

Granted

 

504,351

 

$

33.92

 

Vested

 

(295,852

)

$

25.88

 

Forfeited

 

(45,008

)

$

28.14

 

Non-vested, at September 30, 2006

 

519,590

 

$

28.71

 

In measuring compensation expense from the grant of RSUs, SFAS No. 123R requires companies to estimate the fair value of the award on the grant date.  The fair value of RSUs has been measured using the Black-Scholes option-pricing model.  The fair value of the RSUs is inherently less than the market value of an unrestricted security; accordingly a fair value calculation is performed to determine the fair value of the grant.  The Company’s computation of expected volatility was based on the historic volatility of St. Mary’s common stock. The Company’s computation of expected life was determined based on historical experience of similar awards, giving consideration to the contractual terms of the stock-based awards, vesting schedules, and expectations of future employee behavior.  The interest rate for periods within the contractual life of the award was based on the U.S. Treasury constant maturity yield at the time of grant.  The fair values of granted RSUs were estimated using the following weighted-average assumptions:

 

 

For the Nine Months

 

 

 

Ended September 30,

 

 

 

2006

 

2005

 

Risk free interest rate:

 

4.70

%

4.03

%

Dividend yield:

 

0.25

%

0.38

%

Volatility factor of the expected market price of the Company’s common stock:

 

36.60

%

26.70

%

Expected life of the awards (in years):

 

3

 

3

 

Upon the adoption of SFAS No. 123R, the deferred compensation balance of $5.6 million related to outstanding RSU awards was reclassified to additional paid-in-capital within the shareholders’ equity section of the balance sheet.  This deferred compensation balance had been recorded in accordance with APB Opinion No. 25.  The Company had recorded compensation expense in periods prior to January 1, 2006, for restricted stock awards based on the intrinsic value on the date of grant.  The intrinsic value

14




was recorded as deferred compensation in a separate component of shareholders’ equity and was amortized to compensation expense over the vesting period.  SFAS No. 123R requires expense recognized subsequent to the adoption date to be based on fair value.

Stock Option Grants Under the Equity Incentive Compensation Plan

The Company has previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and Incentive Stock Option Plan.  The last issuance of stock options was December 31, 2004.  Stock options to purchase shares of the Company’s common stock had been issued to eligible employees and members of the Board of Directors.  All options granted to date under the option plans have been granted at exercise prices equal to the respective closing market price of the Company’s common stock on the grant dates, which generally occurred on the last date of a fiscal period.  All stock options granted under the option plans are exercisable for a period of up to ten years from the date of grant.

During the nine-month period ended September 30, 2006, the Company recognized stock-based compensation expense of approximately $1.6 million related to unvested stock options that were outstanding as of January 1, 2006.  There was no cumulative effect adjustment from the adoption of SFAS No. 123R.

Prior to adopting SFAS No. 123R, all tax benefits resulting from the exercise of stock options were presented as operating cash flows in the consolidated statement of cash flows. SFAS No. 123R requires cash flows resulting from excess tax benefits to be classified as a part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for exercised options in excess of the deferred tax asset attributable to stock compensation costs for such options. As a result of adopting SFAS No. 123R, $15.1 million of excess tax benefit for the nine months ended September 30, 2006, has been classified as a financing cash inflow.  Cash received from option exercises under all share-based payment arrangements for the three-month periods ended September 30, 2006, and 2005, was $1.1 million and $1.7 million, respectively, and cash received from option exercises under all share-based payment arrangements for the nine-month periods ended September 30, 2006, and 2005, was $15.6 million and $7.9 million, respectively.

 

15




The following table illustrates the effect on operating results and per share information had the Company accounted for share-based compensation in accordance with SFAS No. 123R for the periods indicated:

 

 

For the Three Months
Ended September 30, 2005

 

For the Nine Months
Ended September 30, 2005

 

 

 

(In thousands, except per share amounts)

 

Net income -

 

 

 

 

 

As reported:

 

$

27,334

 

$

100,698

 

Add: Stock-based employee compensation expense included in reported net income, net of related tax effects

 

1,925

 

3,344

 

Less: Stock-based employee compensation expense determined under fair value-based method for all awards, net of related income tax effects

 

(2,335

)

(4,775

)

Pro forma net income

 

$

26,924

 

$

99,267

 

 

 

 

 

 

 

Basic net income per share -

 

 

 

 

 

As reported

 

$

0.48

 

$

1.77

 

Pro forma

 

$

0.48

 

$

1.74

 

 

 

 

 

 

 

Diluted net income per share -

 

 

 

 

 

As reported

 

$

0.42

 

$

1.55

 

Pro forma

 

$

0.42

 

$

1.53

 

For purposes of these pro forma disclosures, the estimated fair value of the options and employee stock purchase plan (“ESPP”) grants are amortized to expense over the awards’ vesting periods.  The effects of applying SFAS No. 123R in the pro forma disclosure are not necessarily indicative of actual future amounts.

The fair value of options and ESPP grants has been measured at the date of grant using the Black-Scholes option-pricing model.  No options were granted during the nine-month periods ended September 30, 2006, and 2005.  For the ESPP offering periods during 2006, the Company has expensed $186,000 based on the estimated fair value on the respective grant dates.

The following table summarizes the stock options outstanding as of September 30, 2006, as well as activity during the nine months then ended:

 

 

Options

 

Weighted-
Average
Exercise
Price

 

Weighted-
Average
Remaining
Contractual
Term

 

Aggregate
Intrinsic
Value

 

 

 

 

 

 

 

 

 

(In thousands)

 

Outstanding at beginning of period

 

4,698,243

 

$

12.21

 

 

 

 

 

Exercised

 

(1,371,313

)

$

11.41

 

 

 

 

 

Forfeited

 

 (87,005)

 

$

14.33

 

 

 

 

 

Outstanding at end of period

 

3,239,925

 

$

12.48

 

5.56

 

$

78,480

 

Exercisable at end of period

 

3,046,324

 

$

12.43

 

5.51

 

$

73,958

 

16




As of September 30, 2006, there was $659,000 of total unrecognized compensation cost related to unvested stock option awards.

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable.  In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility.  The Company’s stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management’s opinion that the valuations afforded by the existing models are different from the value that the options would realize if traded in the market.

Note 6 — Income Taxes

Income tax expense for the three-month and nine-month periods ended September 30, 2006, and 2005, differs from the amounts that would be provided by applying the statutory U.S. Federal income tax rate to income before income taxes primarily due to the effect of state income taxes, percentage depletion, the estimated effect of the domestic production activities deduction allowed under the American Jobs Creation Act of 2004, and other permanent differences. 

 

 

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

 

 

(In thousands)

 

(In thousands)

 

Current portion of income tax expense (benefit):

 

 

 

 

 

 

 

 

 

Federal

 

$

(766

)

$

21,867

 

$

17,374

 

$

45,360

 

State

 

102

 

1,738

 

880

 

3,152

 

Deferred portion of income tax expense (benefit):

 

29,929

 

(8,617

)

64,612

 

9,485

 

Total income tax expense

 

$

29,265

 

$

14,988

 

$

82,866

 

$

57,997

 

 

 

 

 

 

 

 

 

 

 

Effective tax rates

 

34.4

%

35.4

%

36.1

%

36.5

%

 

The change in tax rate in the current quarter from the previous year reflects differences between the two quarters in the composition of the estimated highest marginal state tax rate as a result of 2006 Texas legislation instituting a new margin tax that will be effective for future tax periods and different impacts of acquisition and drilling activity between periods. It also reflects differing effects from the Company’s estimate of the effect of the domestic production activities deduction, estimated percentage depletion and the possible impact of state tax permanent differences.

Note 7 — Long-term Debt

Revolving Credit Facility

The Company executed an Amended and Restated Credit Agreement on April 7, 2005, to replace its previous credit facility. This credit facility specifies a maximum loan amount of $500 million and has a maturity date of April 7, 2010.  Borrowings under the facility are secured by a pledge in favor of the lenders of collateral that includes certain oil and gas properties and the common stock of the material subsidiaries of the Company.  The borrowing base under the credit facility as authorized by the bank group is currently $900 million, and is subject to regular semi-annual re-determinations.  The borrowing base re-determination process considers the value of St. Mary’s oil and gas properties and other assets, as

17




determined by the bank syndicate.  The Company has elected an aggregate commitment amount of $200 million under the credit facility. The Company will expand the commitment amount in December 2006, in order to pay for the acquisition described in Note 12.  The Company must comply with certain financial and non-financial covenants.  Interest and commitment fees are accrued based on the borrowing base utilization percentage table below.  Euro-dollar loans accrue interest at LIBOR plus the applicable margin from the utilization table, and Alternative Base Rate (ABR) loans accrue interest at prime plus the applicable margin from the utilization table.  Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the consolidated statements of operations.

Borrowing base utilization percentage

 

<50%

 

≥50%<75%

 

≥75%<90%

 

≥90%

 

Euro-dollar loans

 

1.000

%

1.250

%

1.500

%

1.750

%

ABR loans

 

0.000

%

0.250

%

0.250

%

0.500

%

Commitment fee rate

 

0.250

%

0.300

%

0.375

%

0.375

%

The Company had $66 million in loans outstanding under its revolving credit agreement as of September 30, 2006.

5.75% Senior Convertible Notes Due 2022

As of September 30, 2006, the Company had $100 million in outstanding borrowings under the Convertible Notes.  The Convertible Notes provide for the payment of contingent interest of up to an additional 0.5 percent during six-month interest periods based on the note trading price before the beginning of the particular six-month period.  Under that provision, interest was accrued at a total rate of 6.25 percent for the three-month and nine-month periods ended September 30, 2006, and 2005.  Based on the trading price of the Convertible Notes over the determination period, the Company will be subject to the contingent interest payments for the period from September 15, 2006, to March 14, 2007.  The Company has the option to call the Convertible Notes in March 2007.  By doing so, the Convertible Note holders will have the right to convert the Convertible Notes to shares at the conversion price of $13 per share.

Weighted-Average Interest Rate Paid

The weighted-average interest rates paid for the three-month periods ended September 30, 2006, and 2005, were 7.5 percent and 7.2 percent, respectively, including commitment fees paid on the unused portion of the credit facility aggregate commitment, amortization of deferred financing costs, amortization of the contingent interest embedded derivative associated with the Convertible Notes, and the effects of interest rate swaps.  The weighted-average interest rates paid for the nine-month periods ended September 30, 2006 and 2005, were 7.9 percent and 7.1 percent, respectively.  Capitalized interest costs for the Company for the three-month periods ended September 30, 2006, and 2005 were $896,000 and $516,000, respectively, and capitalized interest costs for the nine-month periods ended September 30, 2006, and 2005, were $2.3 million and $1.4 million, respectively.

18




Note 8 — Derivative Financial Instruments

The Company recognized a net gain of $4.5 million from its derivative contracts for the three-month period ended September 30, 2006, compared to a net loss of $8.7 million for the same period in 2005.  Comparative amounts for the nine months ended September 30, 2006, and 2005, were a net gain of $8.9 million and a net loss of $10.5 million, respectively.

The following table summarizes derivative instrument gain (loss) activity:

 

 

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

 

 

(In thousands)

 

(In thousands)

 

Derivative contract settlements realized in oil and gas hedge gain (loss)

 

$

4,828

 

$

(8,441

)

$

14,808

 

$

(8,967

)

Ineffective portion of hedges qualifying for hedge accounting included in unrealized derivative loss

 

(433

)

(306

)

(6,187

)

(1,328

)

Non-qualified derivative contracts included in unrealized derivative loss

 

366

 

365

 

859

 

17

 

Interest rate derivative contract settlements

 

(275

)

(275

)

(550

)

(247

)

Total

 

$

4,486

 

$

(8,657

)

$

8,930

 

$

(10,525

)

Oil and Gas Commodity Hedges

To mitigate a portion of the potential exposure to adverse market changes, the Company has entered into various derivative contracts.  The Company’s derivative contracts in place include swap and collar arrangements for the sale of oil and natural gas.  Please refer to the tables under Summary of Oil and Gas Production Hedges in Place in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for details regarding the Company’s hedged volumes and associated prices.  As of September 30, 2006, the Company has hedge contracts in place through 2011 for a total of approximately 10 million Bbls and 77 million MMBtu of anticipated production.  Subsequent to quarter end, the Company has hedged additional oil and gas volumes in conjunction with the Permian acquisition described in Note 12.  The Company anticipates that all forecasted transactions will occur by the end of their originally specified periods.  All contracts are entered into for other than trading purposes.

The Company attempts to qualify its oil and natural gas derivative instruments as cash flow hedges for accounting purposes.  As of September 30, 2006, all oil and natural gas derivative instruments qualified as cash flow hedges for accounting purposes.  The estimated fair value of oil and natural gas derivative contracts designated and qualifying as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), was a net liability of $1.4 million at September 30, 2006.

Gains or losses from the settlement of oil and gas derivative contracts are reported in the total operating revenues section on the consolidated statements of operations.  Changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings.  Any change in fair value resulting from ineffectiveness is recognized currently in unrealized derivative loss (gain) in the consolidated statement of operations.

19




The Company seeks to minimize ineffectiveness by entering into oil derivative contracts indexed to NYMEX and gas contracts indexed to regional index prices associated with pipelines in proximity to the Company’s areas of production.  As the Company’s derivative contracts contain the same index as the Company’s sale contracts, this results in hedges that are highly correlated with the underlying hedged item.

Unrealized derivative losses for the three-month periods ended September 30, 2006, and 2005, were $433,000 and $306,000, respectively, from the ineffective portion of oil and natural gas derivative contracts.  Amounts for the nine-month periods ended September 30, 2006, and 2005, were net losses of $6.2 million and $1.3 million, respectively.

As of September 30, 2006, the amount of unrealized gain related to oil and gas commodity hedges, net of deferred income taxes, to be reclassified from accumulated other comprehensive income to oil and gas production operating revenues in the next twelve months was $22.6 million.

Interest Rate Derivative Contracts

The Company has various interest rate derivative contracts.  There are offsetting trades that have fixed the future payments under these derivative contracts.  The fair value of the interest rate derivatives was a liability of $255,000 as of September 30, 2006.  The Company recorded net derivative gain in the consolidated statements of operations of $128,000 for the three-month period ended September 30, 2006, and a net gain of $132,000 for the three-month period ended September 30, 2005, from mark-to-market adjustments for these derivatives.  Comparative amounts for the nine-month periods ended September 30, 2006, and 2005, were a net derivative gain of $391,000 and a net derivative loss of $344,000, respectively.  These derivatives do not qualify for fair value hedge treatment under SFAS No. 133 and related pronouncements.

Convertible Note Derivative Instruments

The contingent interest provision of the Convertible Notes is considered an embedded equity-related derivative that is not clearly and closely related to the fair value of an equity interest and therefore must be separately accounted for as a derivative instrument.  The value of the derivative at issuance of the Convertible Notes in March 2002 was $474,000.  This amount was recorded as a decrease to the Convertible Notes payable in the consolidated balance sheets.  Interest expense for each three-month period includes $24,000 of amortization of this derivative.  The unrealized derivative loss (gain) line in the consolidated statements of operations includes net gains of $238,000 and $233,000 for the three-month periods ended September 30, 2006, and 2005, respectively, and $468,000 and $361,000 for the nine-month periods ended September 30, 2006, and 2005, respectively, from mark-to-market adjustments for this derivative.  The derivatives had no net fair value at September 30, 2006.

Note 9 — Pension Benefits

The Company’s employees participate in a non-contributory pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”).  The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Non-qualified Pension Plan”).

20




Components of Net Periodic Benefit Cost

The following table presents the components of the net periodic cost for both the Qualified Pension Plan and the Non-qualified Pension Plan:

 

 

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

 

 

(In thousands)

 

(In thousands)

 

Service cost

 

$

422

 

$

346

 

$

1,264

 

$

1,039

 

Interest cost

 

163

 

134

 

489

 

401

 

Expected return on plan assets

 

(107

)

(94

)

(297

)

(283

)

Amortization of net actuarial loss

 

74

 

60

 

222

 

181

 

Net periodic benefit cost

 

$

552

 

$

446

 

$

1,678

 

$

1,338

 

Gains and losses in excess of ten percent of the greater of the benefit obligation and the market-related value of assets are amortized over the average remaining service period of active participants.

Contributions

St. Mary contributed $1.3 million to the Qualified Pension Plan during the second quarter of 2006.  No further contributions are planned for the remainder of 2006.

Note 10 — Asset Retirement Obligations

 The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties.  A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired.  The increase in carrying value is included in proved oil and gas properties in the consolidated balance sheets.  The Company depletes the amount added to proved oil and gas property costs and recognizes accretion expense in connection with the discounted liability over the remaining estimated economic lives of the respective oil and gas properties.  Cash paid to settle asset retirement obligations is included in the operating section of the Company’s consolidated statement of cash flows.

The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements.  The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised.  The credit-adjusted risk-free rates used to discount the Company’s abandonment liabilities range from 6.50 percent to 7.25 percent.  Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.

21




A reconciliation of the Company’s asset retirement obligation liability is as follows:

 

 

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

 

 

(In thousands)

 

(In thousands)

 

Beginning asset retirement obligation

 

$

69,011

 

$

44,383

 

$

66,078

 

$

40,911

 

Liabilities incurred

 

1,106

 

8,813

 

2,864

 

11,212

 

Liabilities settled

 

(131

)

(499

)

(1,293

)

(858

)

Accretion expense

 

1,222

 

850

 

3,559

 

2,282

 

Ending asset retirement obligation

 

$

71,208

 

$

53,547

 

$

71,208

 

$

53,547

 

Note 11 — Repurchase of Common Stock

Stock Repurchase Program

In July 2006 the Company’s Board of Directors approved an increase to the remaining authorized number of shares that can be repurchased under the Company’s original authorization approved in August 1998 by an additional 5,473,182 sharesAs of the date of this filing the Company has Board authorization to repurchase up to six million shares of common stock.  The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of St. Mary’s existing credit facility agreement and compliance with securities laws.  Stock repurchases may be funded with existing cash balances, internal cash flow and borrowings under the credit facility.

During the first six months of 2006, the Company repurchased a total of 3,319,300 shares of its common stock under the program at a weighted-average price of $37.09 per share, including commissions.  No additional shares were repurchased under the program during the third quarter of 2006. In July 2006 the Company retired 3,275,689 shares of treasury stock.

Note 12 — Subsequent Event

On November 1, 2006, the Company signed a purchase and sale agreement to purchase the working and net revenue interests, as well as the underlying leasehold interest in oil and gas assets in West Texas from two private parties for $250 million in cash funded from the Company’s existing credit agreement.  The properties target producing formations in the Spraberry interval.  The Company estimates that proved reserves attributable to the acquisition are 78.1 BCFE, which are producing approximately 16.0 MMCFED net.  The properties are approximately 79 percent oil and 21 percent natural gas and associated liquids.  The acquired interests will be operated by St Mary, and have an  average working interest of 95 percent and net revenue interest of approximately 71 percent.  It is anticipated that the acquisition will close by December 15, 2006.

This transaction adds high working interest, low risk properties to the Company’s portfolio and increases our presence in our Permian Basin core area.  The acquisition adds a multi-year drilling program to the Company’s inventory of projects with potential for downspacing that has the potential to  have meaningful upside.

A third party has a contractual right to purchase up to an undivided twenty percent of the working interest in the transaction.  This third party’s right must be exercised concurrent with closing of the transaction.

22




St. Mary has hedged the first five years of oil volume production in conjunction with this transaction using swaps.  The average annual prices for these swaps are between $65.15 and $68.04 per Bbl.  The Company has also hedged the anticipated production for residual natural gas over a five year period at a weighted average NYMEX equivalent price of approximately $7.70 per MMBTU and natural gas liquids for the first two years.

Note 13 —Recent Accounting Pronouncements

In July 2006 the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in tax positions.  FIN 48 will require that the Company recognize the impact of a tax position in its financial statements if the technical merits of that position indicate that the position is more likely than not of being sustained upon audit.  The provisions of FIN 48 will be effective as of the beginning of the Company’s 2007 fiscal year, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings.  The Company is currently evaluating the impact of adopting FIN 48 on its financial statements.

In September 2006 the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), to address diversity in practice in quantifying financial statement misstatements.  SAB 108 requires misstatements to be quantified based on their impact on each of our financial statements and related disclosures. SAB 108 provides for registrants to correct prior year financial statements for immaterial errors in subsequent filings of prior year financial statements and does not require previously filed reports to be amended.  SAB 108 will be effective for the Company as of December 31, 2006.  The SAB also allows for a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108.  Based on its evaluation at this time, the Company does not expect the adoption of this standard to have any effect on its historical financial statements.

In September 2006 the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements.  The provisions of SFAS No. 157 will be effective as of the beginning of the Company’s 2008 fiscal year. The Company is currently evaluating the impact SFAS No. 157 will have on its financial statements.

In September 2006 the FASB issued Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”).  SFAS No. 158 will require that the Company recognize the excess of the Projected Benefit Obligation over the fair value of the plans’ assets of its Qualified and Non-qualified Pension Plans as a liability in the 2006 year-end balance sheet. The cumulative balance sheet entry will be recorded against accumulated other comprehensive income.  This statement does not affect how an entity computes its benefit expense recognized in the income statement. The Company estimates the impact of adopting SFAS No. 158 to be an increase to the liability of approximately $3 million to $6 million, with no impact to the statement of operations or cash flows.  The Company currently uses December 31 as the measurement date for measuring the fair value of the plan assets, and accordingly will not be affected by this transition provision of SFAS 158 as it relates to valuing the plan assets.

23




 

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

This discussion contains forward-looking statements.  Please refer to “Cautionary Information About Forward-Looking Statements” at the end of this item for an explanation of these types of statements.

General Overview

We are an independent energy company focused on the exploration, exploitation, development, acquisition, and production of natural gas and crude oil in the United States.  We earn greater than 90 percent of our revenues from the sale of produced natural gas and crude oil.  These sales also comprise the vast majority of our cash flows from operations.  Our oil and gas reserves and operations are concentrated in various Rocky Mountain basins, including the Williston, Big Horn, Wind River, Powder River, and Greater Green River Basins; the Mid-Continent Anadarko and Arkoma Basins; the tight sandstone and limestone reservoirs of East Texas and North Louisiana; the Permian Basin; onshore Gulf Coast and offshore Gulf of Mexico.  We have developed a portfolio of proved reserves, development drilling opportunities, resource development opportunities, and non-conventional gas prospects.

Third Quarter 2006 Operating and Financial Highlights

Our third quarter net income was a record at $55.9 million or $0.88 per diluted share compared to third quarter 2005 results of $27.3 million or $0.42 per diluted share.  Production for the third quarter was 23.2 BCFE.  This represents a three percent increase from the second quarter 2006 and is basically flat from the previous third quarter. Per MCFE lease operating expense and transportation expense increased $0.33 to $1.40 as compared to a year ago.  We are seeing increased lease operating expense in every region compared to last year due to a combination of increased equipment and service cost and more workover activity.  The increase in commodity prices over the past several years has led to increased levels of drilling activity and has created an incentive to perform maintenance and workover activity on wells and infrastructure which may not have been performed in lower commodity price environments.  While the demand for equipment and services has increased dramatically, the available supply from vendors has not increased at the same rate.  Accordingly, equipment and service providers have been able to raise their prices in a period where we were increasing our activity.  Most significantly, workover activity has increased as we repaired and upgraded properties associated with recent acquisitions in the Rockies.  The economic viability of these workover projects is subjected to the same rigorous evaluation process as our decisions to drill a well.  Additionally, we had several high-dollar workover operations on a few high-value properties in the Mid-Continent and the Rockies.  Production taxes decreased $0.04 to $0.54 per MCFE.

This third quarter represents the third consecutive quarter of sequential growth in production and we are forecasting sequential growth in the fourth quarter of 2006 as well.   These increases occurred despite shut-in production on a significant royalty well and delays in securing drilling rigs. We entered into agreements to acquire an additional $21 million of oil and gas properties during the third quarter, of which $5 million is located in the Rockies and closed during the quarter. The remaining $16 million includes properties located in the Permian and Anadarko Basins and closed during the fourth quarter.  However, in this competitive acquisition market, these acquisitions will not have as significant an impact on our production as we had forecast for our 2006 acquisitions budget.

Our DD&A, including ARO accretion expense, increased $0.12 to $1.72 per MCFE during the quarter.  This increase is attributed to a slightly lower denominator in the DD&A calculation for the third quarter resulting from a reduction in tail reserves due to lower commodity prices used in the reserve preparation as of quarter end.  Additionally, our per MCFE finding cost of oil and gas reserves has

24




 

increased in recent years, reflecting the aforementioned cost increases.  We discuss these financial results and trends in more detail below.

Acquisition of Permian Basin Oil and Gas Properties

On November 1, 2006, we signed a purchase and sale agreement with an undisclosed seller to purchase the working and revenue interests, as well as the underlying leasehold interest in oil and gas assets in West Texas from two private parties for $250 million in cash funded from our existing credit agreement.  The properties are located in the Midland Basin and target the producing formations in the Spraberry interval and will be part of our Permian core area.  We estimate that proved reserves attributable to the acquisition are 78.1 BCFE, which are producing approximately 16.0 MMCFED, net.  The properties are approximately 79 percent oil and 21 percent natural gas and associated liquids.  The acquired interests will be 100 percent operated, with average working interest of 95 percent and net revenue interest of approximately 71 percent.  It is anticipated that the acquisition will close by December 15, 2006.

This transaction adds high working interest, low risk properties to our portfolio and increases our presence in the Permian Basin.  The acquisition adds a multi-year drilling program to our inventory of projects with potential for downspacing that could have meaningful upside.

A third party has a contractual right to purchase up to an undivided twenty percent of the working interest in the transaction.  This third party’s right must be exercised concurrent with closing of the transaction.

We have hedged the first five years of oil volume production in conjunction with this transaction using swaps.  The average annual prices for these swaps are between $65.15 and $68.04 per Bbl.  We hedged the residual natural gas production over a five year period at a weighted average NYMEX equivalent price of approximately $7.70 per MMBTU.  An additional two years of anticipated natural gas liquids production have also been hedged.

Oil and Gas Prices

Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. We sell the majority of our natural gas on contracts which use first of the month (also frequently referred to as bid week) index pricing, which means that gas produced in that month is sold at the first of the month price regardless of the spot price on the day it is produced.  Our crude oil is sold on contracts that pay us the average of the posted prices for the period in which the crude oil is sold.

The average Henry Hub bid week natural gas price decreased by four percent and the average NYMEX oil price remained flat between the second quarter and third quarter of 2006.  While average quarterly bid week natural gas prices remained relatively flat between the second and third quarters of 2006, both were down substantially relative to the first quarter of 2006.  Spot prices weakened materially through the last half of September, which resulted in a Henry Hub bid week price for October 2006 of $4.20 per MMBtu.  Although the spot prices at Henry Hub have increased since the end of September, there has been an overall decrease in the 36-month forward strip price for natural gas.  For example, the average 36-month strip for Henry Hub was $8.73 per MMBtu at June 30, 2006, and was $7.49 per MMBtu as of September 30, 2006.  Most analysts suggest that the primary reasons for this decrease in price are historically high levels of natural gas in storage resulting from mild weather in the last 12 months and less hurricane activity in the Gulf of Mexico this year compared to last year.

25




 

Crude oil prices reached an all-time high early in the third quarter of 2006 as ongoing tensions in the Middle East escalated.  The price of crude oil then decreased significantly over the course of the quarter as hostilities in the Middle East eased.  Consequently, the average NYMEX crude oil price was essentially flat between the second and third quarters of this year.  The average crude oil price in the third quarter was $70.48 per barrel.  However, included in this price was movement of prices within the quarter.  For example, the average price in July was $74.46 per barrel compared to $63.90 per barrel in September.  On a percentage basis, the differential for crude oil was consistent throughout the third quarter of 2006.  The three year NYMEX strip at the end of the third quarter of 2006 has decreased to $66.84 per Bbl compared to $74.39 per Bbl at the end of July.

While the changes in the quoted NYMEX oil and Henry Hub natural gas prices are generally used as a basis for comparison within the industry, the realized price that we receive for oil and natural gas is effected by quality, energy content, and transportation differentials for these products.  We refer to this price as our net realized price and it excludes the effects of hedging.  Our realized price is further impacted by the result of our hedging contracts that have settled over the corresponding months.  We refer to this price as our net realized price, including the effects of hedging. 

 

 

For the Three
Months Ended
September 30, 2006

 

For the Nine
Months Ended
September 30, 2006

 

 

 

 

 

 

 

Natural Gas (per MMBtu):

 

 

 

 

 

NYMEX price

 

$

6.53

 

$

7.47

 

Net realized price

 

$

6.41

 

$

6.70

 

Net realized price, including the effects of hedging

 

$

7.14

 

$

7.44

 

 

 

 

 

 

 

Crude Oil (per Bbl):

 

 

 

 

 

NYMEX price

 

$

70.48

 

$

68.22

 

Net realized price

 

$

65.02

 

$

61.83

 

Net realized price, including the effects of hedging

 

$

61.28

 

$

58.41

 

 

Our natural gas price realizations for the three months ended September 30, 2006, were improved by $10.4 million of realized hedging gains while our oil price realization was negatively impacted by $5.6 million of realized hedging losses.  For the nine months ended September 30, 2006, our natural gas price realizations were improved by $30.1 million of realized hedging gains and our oil price realization was negatively impacted by $15.3 million of realized hedging losses.  Our reported differentials for natural gas in the third quarter of 2006 are improved from the prior quarter.  This is due to unanticipated updated information received on gas producing properties operated by others relating to prior quarters, the impact of which benefited us in the third quarter.  Overall, we believe we receive natural gas prices similar to those of our competitors and we expect that our differentials will be $0.65 to $0.75 in the fourth quarter of 2006.

Cost Environment

We believe there is a highly dynamic relationship between service costs and commodity prices and that it is not possible to predict when the break-over point of one relative to the other will occur.  Increases in rig rates, field service costs, workover costs, and materials prices continue to pressure the exploration and production sector.  Cost escalation in the service sector continues to affect our business.  Scarcity of equipment and services has compounded this issue in many of our regions, but we are beginning to note instances where equipment and service availability seems to be improving.  With the forward commodity price curves softening between ten to twenty percent, we expect that the rate of cost

26




 

increases will slow and that a leveling or even a decrease in service costs may follow.  That being said, we believe we can not predict the timing of changes in the cost environment.  We know that in most cases, a phase of extended commodity price increases is followed by increases in service costs and that extended decreases in prices lead to a decrease in service costs.  The concern for the exploration and production industry is the period when commodity prices decline and the costs either continue to escalate or remain at high levels. This period of time is particularly challenging to manage.  As a result, we evaluate current economics on an individual investment basis, as part of our normal investment decision process.  We have a formal process for establishing our drilling budget, and our prospect inventory and our strong balance sheet give us the flexibility to adjust this budget as additional opportunities arise or as the expected economics of our planned activities change.

As of the current time, our exploration and development budget for 2006 is $492 million which contemplates the current cost environment.  The current budget reflects the timing of drilling projects which have been impacted by service availability issues, timing of permitting, and the postponement of selected projects due to unfavorable economics in the current price and cost environment.  The acquisition budget reflects oil and gas property acquisitions of approximately $35 million, which have closed through the date of this filing, $16 million of which closed after the end of the third quarter. We anticipate closing on an additional $250 million of property transactions before the end of the calendar year.  The Permian acquisition of oil and gas properties solidifies our platform for growth in this core area with an additional inventory of high working interest, low risk drilling opportunities.

Hedging Activities

We have an active hedging program in which we hedge the first two to five years of an acquisition’s risked production, as well as a portion of our existing forecast production on a discretionary basis.  In the fourth quarter of 2005, we hedged a significant portion of anticipated future production from our currently producing properties using zero-cost collars.  These contracts were a supplement to our previous swap and collar contracts.  In January 2006, we hedged a portion of specific forecast natural gas production for 2006 and 2007 using swap contracts.  Additionally, we hedged anticipated future production in conjunction with the execution of our stock repurchase program in the second quarter of this year.  In conjunction with the stock repurchase program, we hedged an amount of reserves that were represented by the proportionate number of total outstanding shares repurchased.

Taking into account all oil and gas production hedge contracts placed through September 30, 2006, we have hedged approximately 10 million Bbls and 77 million MMBtu of our anticipated crude oil production through the year 2011.  We have hedged an estimated 60 percent of our remaining 2006 forecast oil production volumes and 35 percent of our remaining 2006 forecast natural gas production volumes using both zero-cost collars and swap contracts.  In conjunction with the Permian Basin acquisition, we hedged additional anticipated production for the five years subsequent to closing.  The average annual prices for these oil swaps are between $65.15 and $68.04 per Bbl.  Although a smaller component of the overall value from the acquisition, we also hedged natural gas liquids covering the first two years and natural gas for the first five years after the acquisition.  Using current differentials, we estimate that the break-even NYMEX prices for the natural gas commodities derivatives is approximately $8.39 per MMBtu over the remainder of 2006.  For crude oil, we essentially participate in the market from prices of approximately $53 per Bbl to approximately $71 per Bbl.  This will become more weighted to the higher end of the range because of the swaps recently executed in conjunction with the acquisition.  Below the floor, our realizations should be better than NYMEX pricing and above the ceiling price our realization should be less than NYMEX pricing.

Primarily because of the basis expansion affecting oil in the Rockies, we recorded approximately $433,000 of ineffectiveness related to our derivative contracts in the third quarter of 2006 and $6.2 million related to ineffectiveness was recorded for the nine months ended September 30, 2006.  Despite this ineffectiveness, we continue to have adequate correlation to maintain the accounting designation for these derivatives as cash flow hedges.  Please see Note 8 — Derivative Financial Instruments in Part I,

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Item 1 of this report for additional information regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas Production Hedges in Place, later in this section.

Share Repurchase Program

During the third quarter of 2006, our Board authorized an increase in the number of shares available for repurchase under the plan by an additional 5,473,182 shares to a total of six million shares.  Management plans to continue to evaluate the repurchase of common stock as a part of our business plan. We evaluate the market price of our common stock relative to our assessment of net asset value per share.  To the extent the market price is sufficiently below what we believe to be the net asset value per share, we will repurchase shares under the program.  As of the end of September 2006, we had 6,000,000 shares remaining for authorized repurchase.  In April and May of 2006, we repurchased 3,319,300 shares under the share repurchase program.

Net Profits Plan

Current period cash payments and accruals that have been expensed as compensation costs under the Net Profits Plan total $6.8 million and $20.6 million for the three-month and nine-month periods ended September 30, 2006, respectively.  These amounts are slightly lower than originally budgeted due to increased capital spending in existing payout pools, a decrease in the timing of payout for newer pools, and a relative decrease in natural gas prices since the time the 2006 budget was developed. The actual cash payments we make are dependent on actual production, realized prices, and operating and capital costs associated with the properties in each individual pool.  Actual cash payments will be inherently different from the estimated liability amounts.

With respect to the accounting estimate of the liability associated with future estimated payments from our Net Profits Plan, we have recorded $17.4 million of expense for the nine month period ended September 30, 2006.  We note that this liability has decreased by $3.7 million from June 30, 2006, to September 30, 2006.  This decrease in the quarter is related to the decrease in the overall commodity price environment over the last quarter, as described earlier. While we have forecast that this liability will again increase in the fourth quarter of this year, it is not possible to predict this with certainty due to the impact that commodity prices and reserve estimates have on the valuation of this estimated liability.  Based on current projections, we estimate that the total expense for the full year 2006 related to the change in the estimated liability associated with future estimated payments from our Net Profits Plan that will be recorded in the statement of operations will be approximately $28 million.  Please see the additional discussion and analysis in the Comparison of Financial Results and Trends section below.

The calculation of the estimated liability associated with the Net Profits Plan requires management to prepare an estimate of future amounts payable from the Net Profits Plan.  On a monthly basis, we calculate estimates of the payments to be made for each individual pool under the Net Profits Plan.  The underlying principal factors for our estimates are forecasted oil and gas production from the properties that comprise each individual pool, price assumptions, cost assumptions, and discount rate.  In most cases, the cash flow streams used in these calculations will span more than 20 years.  We generally use a 15 percent discount rate to calculate the present value of these future payments, and the resulting amount is recorded as a liability.  Commodity prices impact the calculated cash flows during periods after payout and can dramatically affect the timing of the estimated date of payout of the individual pools.  Our commodity price assumptions are currently determined from an average of actual prices realized over the prior 24 months together with adjusted NYMEX strip prices for the ensuing 12 months for a total of 36 months of data.  This average is supplemented by including the effect of hedge prices for the percentage of forecasted hedged production in the relevant period.  The calculation of the estimated liability for the Net Profits Plan is highly sensitive to our price estimates and discount rate assumptions. For example, if we changed the commodity prices in our calculation by ten percent, the liability recorded on the balance sheet at September 30, 2006, would differ by approximately $32 million.  A one

28




 

percentage point change in the discount rate would result in a change of approximately $7 million.  We frequently evaluate the assumptions used in our calculations to evaluate the possible impacts stemming from the current market environment, including current and future oil and gas prices, discount rates, and overall market conditions.

Stock-Based Compensation

On January 1, 2006, we adopted SFAS No. 123R, Share Based Payments, which requires the measurement of compensation expense for all stock-based awards made to employees and directors.  The stock-based awards specific to us include stock options, employee stock purchases under the Employee Stock Purchase Plan, and restricted stock units granted under the Restricted Stock Plan and future restricted stock units to be granted under the Equity Incentive Compensation Plan.  We adopted SFAS No. 123R using the modified prospective transition method.  Our consolidated financial statements as of and for the three-months and nine-months ended September 30, 2006, reflect the impact of SFAS No. 123R.  Total stock-based compensation expense for the three and nine months ended September 30, 2006, was approximately $2.6 million and $9.2 million, respectively, which included $691,000 and $1.8 million, respectively, of expenses related to stock options and employee stock purchases under the ESPP recognized under SFAS No. 123R.  Upon adoption of SFAS No. 123R, we have expensed all costs associated with grants to individuals that do not have a future service requirement due to their existing term of service to us or due to the fact that their age implies that any such awards are immediately vested.

As part of hiring a new senior executive in the second quarter of 2006, we granted a special stock award of 20,000 shares which vested immediately upon commencement of employment.  Approximately $728,000 of compensation expense was recorded related to this award.  An additional award has been issued whereby the employee may earn an additional 20,000 shares contingent on certain service and performance conditions.  The fair value of this award will be recorded to compensation expense over the vesting period based on an assessment of the likelihood of achievement of the performance condition.  As of September 30, 2006, approximately $50,000 of compensation expense had been recorded related to this award.

First Nine Months of 2006 Operating and Financial Highlights

In the first nine months of 2006 our net income was $146.5 million or $2.25 per diluted share compared to the first nine months of 2005 income of $100.7 million or $1.55 per diluted share.  Production for the first nine months of 2006 was 67.7 BCFE.  This represents a three percent increase from the same period a year ago.  Per MCFE lease operating expense and transportation expense increased $0.34 to $1.37 as compared to a year ago. The year to date activity increase over the last year’s comparable period is due to increased costs and higher levels of workover activity.  An increase in commodity prices over the past several years has led to increased levels of drilling and maintenance activity.  Production taxes increased $0.04 to $0.54 per MCFE and DD&A, including ARO accretion expense, increased $0.09 to $1.63 per MCFE.  We discuss these financial results and trends in more detail below.

In addition to the acquisitions described in the third quarter, we closed on a transaction in May 2006, whereby we exchanged non-core oil and gas properties located in the Uinta Basin for oil and gas properties located in Richland County, Montana.  The transaction was structured as an Internal Revenue Code Section 1031 tax-deferred exchange. For financial reporting purposes, the transaction is considered a non-monetary transaction and has been accounted for at estimated fair value, effectively resulting in the exchange being considered two separate transactions: a sale of oil and gas properties and a purchase of oil and gas properties. The exchange of properties resulted in recognition of a book gain of approximately $7 million.

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The table below provides information regarding selected production and financial information for the quarter ended September 30, 2006, and the immediately preceding three quarters.  Additional details of per MCFE costs are contained later in this section. 

 

 

For the Three Months Ended

 

 

 

September 30,

 

June 30,

 

March 31,

 

December 31,

 

 

 

2006

 

2006

 

2006

 

2005

 

 

 

(In millions, except production sales data)

 

Production sales (BCFE)

 

23.2

 

22.6

 

22.0

 

21.9

 

 

 

 

 

 

 

 

 

 

 

Oil and gas production revenues, excluding the effects of hedging

 

$

188.2

 

$

178.0

 

$

184.1

 

$

231.6

 

Lease operating expense

 

$

30.1

 

$

28.3

 

$

26.3

 

$

23.8

 

Transportation costs

 

$

2.4

 

$

2.8

 

$

2.9

 

$

2.6

 

Production taxes

 

$

12.5

 

$

12.2

 

$

12.0

 

$

16.1

 

General and administrative expense

 

$

9.7

 

$

10.4

 

$

10.8

 

$

9.5

 

Net income

 

$

55.9

 

$

40.1

 

$

50.5

 

$

51.2

 

 

 

 

 

 

 

 

 

 

 

Percentage change from previous quarter:

 

 

 

 

 

 

 

 

 

Production (MCFE)

 

3

%

3

%

%

(5

)%

Oil and gas production revenues, excluding the effects of hedging

 

6

%

(3

)%

(21

)%

14

%

Lease operating expense

 

6

%

8

%

11

%

4

%

Transportation costs

 

(14

)%

(3

)%

12

%

44

%

Production taxes

 

2

%

2

%

(25

)%

20

%

General and administrative expense

 

(7

)%

(4

)%

14

%

(3

)%

Net income

 

39

%

(21

)%

(1

)%

88

%

 

Regional summary and Outlook for the Remainder of 2006

While oil and gas prices remain highly volatile and service costs have continued to increase, we have an inventory of drilling prospects that is attractive in various price and cost environments.  We believe we will continue to have access to the drilling rigs we currently operate and are actively seeking an increase in our drilling rig inventory. Adding new rigs may remain a challenge because of the competitive state of the rig market, however we have seen recent indications that the rig market may be softening on a relative basis since rates are holding constant and contract terms seem to be more favorable for producers relative to our experience over the last 24 months.  The absolute level of the escalated rig and other service costs will be closely monitored for the remainder of this year and as we develop our budget for 2007, particularly in marginal gas projects where economics have been pressured as natural gas prices declined due to historically high natural gas storage.

The overall acquisition market remains highly competitive, and we believe that we will be successful in transactions where we have a good working knowledge of the area and we are able to evaluate the technical merits of a project.  We tend to avoid highly marketed transactions as these appear to be very aggressively bid by acquirers.  We continue to maintain a disciplined approach to acquisitions as we actively evaluate acquisition opportunities and the potential impact such transactions will have on net asset value per share.  Over the remainder of 2006 we will continue to execute our business plan, including the following:

·                  Permian Core Area — We will close on the $250 million acquisition of oil and gas properties and integrate these operations into our existing regional structure.  Additionally, we have been more active on a drilling program in West

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Texas which accounts for the increased capital expenditures for the region, on top of the focus on our HJSA prospect and our Parkway Delaware waterflood.

·                  Rockies Conventional — In the third quarter, we successfully completed 16 wells and drilled one dry hole in the Rockies.  In the Bakken play, six wells were completed successfully during the quarter with four wells completing and two wells drilling as of quarter-end.  We continue to exploit the Bakken using a combination of grass roots drilling and re-entry wells. Despite recent industry reports promoting the prospectivity of the North Dakota Bakken, we have generally been disappointed with the results we see there and are not actively drilling farther east of the Montana/North Dakota state line.  We plan to participate in 40 wells in the Bakken in 2006.  We also plan to continue taking advantage of our expertise in the Red River formation and plan to participate in approximately 50 wells exploring the potential of a horizontal program in the Madison and Nisku formations as well as exploring the opportunity to drill infill wells in the Bakken in Montana.  In the Southern Rockies, we recently secured a rig that will be dedicated to drilling four wells through year end in the Wamsutter region targeting the Almond and Lewis formations through year end.  We are also continuing our activity targeting the Tensleep oil zone in the Four Bear, Murphy Dome, Quealy Dome, and Big Sand Draw fields.

·                  Rockies — Hanging Woman Basin Coalbed Natural Gas — As of the date of this filing, we have drilled a total of 330 wells in our Hanging Woman Basin coalbed natural gas project, of which 252 wells are currently producing.  We plan to drill over 140 wells during 2006.  Current production for the project is approximately 12.2 MMCFD gross, 8.1 MMCFD net.

We have recently completed two of the horizontal wells planned to test the deeper coals.  One or two more horizontal wells are planned this year to test the Roberts and deeper Kendrick coals.  Horizontal completion techniques have successfully been used in similar coals in Oklahoma and Australia.  Our water discharge permits for these wells have been approved, and dewatering efforts are underway.  Gas associated with these wells is expected to show in the next two months.  With respect to permitting wells on federal acreage in Montana, the supplemental environmental impact statement required by the Ninth Circuit Court of Appeals is anticipated to be completed in June of 2007.  However, Montana continues to issue permits for wells on state and fee acreage.  We are also evaluating different development alternatives for this project as a whole including the pattern of drilling, the spacing unit for selected areas of the play and the pace of development.

·                  Mid-Continent — At the Centrahoma field, our horizontal efforts have been focused on the drilling to the Woodford shale formations.  We have been operating two rigs in the field and will be adding a third rig in the fourth quarter of 2006.  At quarter end, we had completed five wells targeting the Woodford shale formation.  The most recent two wells have utilized a refined completion technique that resulted in a significantly higher initial production rate than the previous four wells.  We are considering re-fracturing previously drilled horizontal wells in the Woodford utilizing this refined completion technique.  In addition to the Woodford formation, we believe there is potential in the Wapanucka limestone and the Cromwell sandstone.  We have recently increased our acreage position at Centrahoma to 30,000 net, 46,000 gross acres.  We plan to participate in 39 Centrahoma wells in 2006, most of which are horizontal.

The Paggi Broussard #2 well, which is an offset well to the Paggi Broussard #1 well at our Constitution field, began production in July 2006.  As of quarter end, the Paggi Broussard #2 was producing at a gross production rate of 28.0 MMCF and 1,500 Bbls of condensate per day.

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In Northeast Mayfield, we successfully completed six wells during the third quarter.  Six wells were completing and three wells were drilling as of the end of the third quarter.  We operate two drilling rigs in the field.  As the Atoka/Granite Wash program at Northeast Mayfield is sensitive to natural gas prices, we hedged approximately two-thirds of the production of our anticipated 2006 drilling program at the beginning of the year to protect our economics.  We continue to evaluate the economics of proposed wells before drilling to ensure the wells meet minimum economic thresholds, although non-economic factors such as rig utilization for operated rigs are also considered in that decision.

·                  ArkLaTex — During the third quarter, we successfully completed 25 wells out of 27 attempts in the region.  We continue to see improved results from refined stimulation techniques at the Spider field.  There are three wells planned in the Spider field in the last three months of the year. In Elm Grove, development continues to advance southward onto acreage where we have higher working interests.  Sixteen wells are budgeted in Elm Grove for the last three months of the year where two to three non-operated rigs are running at any one time.  Additionally, initial results from recompletions using coiled tubing fracturing treatments targeting the upper Cotton Valley and Hosston formations appear encouraging.  Based on preliminary discussion with the operator of this field, there appears to be a significant amount of activity in the foreseeable future at Elm Grove.

·                  Gulf Coast — We have had five successes in six attempts through the end of the quarter in our low to moderate risk Direct Hydrocarbon Indicator exploration program in the Gulf Coast.  We are utilizing our DHI expertise to advance our inventory of projects.  For the remainder of the year, our activities will focus on bringing on line the discoveries found this year.  We have as many as three additional DHI prospects that could be drilled this year, depending on rig and service availability.  At Judge Digby we had two successful wells and two successful re-completions this year. However, no more activity is planned for 2006 in the field.  On our fee lands, a significant royalty well has been shut in for several months due to mechanical issues in the well bore. We do not anticipate production will be back on line until early 2007.

·                  Our revised production guidance for the full year 2006 is forecast to be between 92 BCFE and 93 BCFE, which exceeds 2005 reported production of 87.4 BCFE by approximately six percent.  This growth is being driven primarily through drilling, workover and recompletion activities.

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A quarter and nine-month overview of selected production and financial information, including trends:

Selected Operations Data (In Thousands, Except Price and Per MCFE Amounts):

 

 

For the Three Months
Ended September 30,

 

% of
Change
Between

 

For the Nine Months
Ended September 30,

 

% of
Change
Between

 

 

 

2006

 

2005

 

Periods

 

2006

 

2005

 

Periods

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net production volumes