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Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

x

Quarterly Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

 

o

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the Quarterly Period ended March 31, 2012

 

Commission File No. 001-31446

 

CIMAREX ENERGY CO.

1700 Lincoln Street, Suite 1800

Denver, Colorado 80203-4518

(303) 295-3995

 

Incorporated in the

 

Employer Identification

State of Delaware

 

No. 45-0466694

 

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

 

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

 

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

 

Large accelerated filer x

 

Accelerated filer o

 

 

 

Non-accelerated filer o
(Do not check if a smaller
reporting company)

 

Smaller reporting company o

 

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

 

The number of shares of Cimarex Energy Co. common stock outstanding as of March 31, 2012 was 85,718,280.

 

 

 



Table of Contents

 

CIMAREX ENERGY CO.

 

Table of Contents

 

 

 

Page

PART I

 

 

 

 

 

Item 1 — Financial Statements

 

 

 

 

 

Condensed consolidated balance sheets (unaudited) as of March 31, 2012 and December 31, 2011

 

4

 

 

 

Consolidated comprehensive statements of operations (unaudited) for the three months ended March 31, 2012 and 2011

 

5

 

 

 

Condensed consolidated statements of cash flows (unaudited) for the three months ended March 31, 2012 and 2011

 

6

 

 

 

Notes to consolidated financial statements (unaudited)

 

7

 

 

 

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

 

21

 

 

 

Item 3 — Qualitative and Quantitative Disclosures About Market Risk

 

35

 

 

 

Item 4 — Controls and Procedures

 

36

 

 

 

PART II

 

 

 

 

 

Item 6 — Exhibits

 

38

 

 

 

Signatures

 

39

 

2



Table of Contents

 

GLOSSARY

 

Bbl/d—Barrels (of oil or natural gas liquids) per day

Bbls—Barrels (of oil or natural gas liquids)

Bcf—Billion cubic feet

Bcfe—Billion cubic feet equivalent

Btu—British thermal unit

MBbls—Thousand barrels

Mcf—Thousand cubic feet (of natural gas)

Mcfe—Thousand cubic feet equivalent

MMBbls—Million barrels

MMBtu—Million British Thermal Units

MMcf—Million cubic feet

MMcf/d—Million cubic feet per day

MMcfe—Million cubic feet equivalent

MMcfe/d—Million cubic feet equivalent per day

Net Acres—Gross acreage multiplied by Cimarex’s working interest percentage

Net Production—Gross production multiplied by Cimarex’s net revenue interest

NGL—Natural gas liquids

Tcf—Trillion cubic feet

Tcfe—Trillion cubic feet equivalent

WTI—West Texas Intermediate

 

One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas

 

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

 

Throughout this Form 10-Q, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934.  These forward-looking statements include, among others, statements concerning our outlook with regard to timing and amount of future production of oil and gas, price realizations, amounts, nature and timing of capital expenditures for exploration and development, plans for funding operations and capital expenditures, drilling of wells, operating costs and other expenses, marketing of oil and gas and other statements of expectations, beliefs, future plans and strategies, anticipated events or trends, and similar expressions concerning matters that are not historical facts.  The forward-looking statements in this report are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by the statements.

 

These risks and uncertainties include, but are not limited to, fluctuations in the price we receive for our oil and gas production, reductions in the quantity of oil and gas sold due to decreased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated, and increased financing costs due to a significant increase in interest rates.  In addition, exploration and development opportunities that we pursue may not result in productive oil and gas properties.  There are also numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures.  These and other risks and uncertainties affecting us are discussed in greater detail in this report and in our other filings with the Securities and Exchange Commission.

 

3



Table of Contents

 

PART I

 

ITEM 1 - Financial Statements

 

CIMAREX ENERGY CO.

Condensed Consolidated Balance Sheets

 

 

 

March 31,

 

 

 

 

 

2012

 

December 31,

 

 

 

(Unaudited)

 

2011

 

 

 

(In thousands, except share data)

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

4,406

 

$

2,406

 

Receivables, net

 

361,553

 

359,409

 

Oil and gas well equipment and supplies

 

84,808

 

85,141

 

Deferred income taxes

 

5,876

 

2,723

 

Other current assets

 

8,480

 

8,216

 

Total current assets

 

465,123

 

457,895

 

Oil and gas properties at cost, using the full cost method of accounting:

 

 

 

 

 

Proved properties

 

10,302,527

 

9,933,517

 

Unproved properties and properties under development, not being amortized

 

642,506

 

607,219

 

 

 

10,945,033

 

10,540,736

 

Less — accumulated depreciation, depletion and amortization

 

(6,525,077

)

(6,414,528

)

Net oil and gas properties

 

4,419,956

 

4,126,208

 

Fixed assets, net

 

123,534

 

118,215

 

Goodwill

 

691,432

 

691,432

 

Other assets, net

 

36,404

 

34,827

 

 

 

$

5,736,449

 

$

5,428,577

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

61,462

 

$

79,788

 

Accrued liabilities

 

364,804

 

385,651

 

Derivative instruments

 

4,333

 

245

 

Revenue payable

 

157,159

 

150,655

 

Total current liabilities

 

587,758

 

616,339

 

Long-term debt

 

572,000

 

405,000

 

Deferred income taxes

 

1,041,257

 

974,932

 

Other liabilities

 

304,972

 

301,693

 

Total liabilities

 

2,505,987

 

2,297,964

 

Stockholders’ equity:

 

 

 

 

 

Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued

 

 

 

Common stock, $0.01 par value, 200,000,000 shares authorized, 85,718,280 and 85,774,084 shares issued, respectively

 

857

 

858

 

Paid-in capital

 

1,912,125

 

1,908,506

 

Retained earnings

 

1,317,095

 

1,221,263

 

Accumulated other comprehensive income (loss)

 

385

 

(14

)

 

 

3,230,462

 

3,130,613

 

 

 

$

5,736,449

 

$

5,428,577

 

 

See accompanying notes to consolidated financial statements.

 

4



Table of Contents

 

CIMAREX ENERGY CO.

 Consolidated Comprehensive Statements of Operations

(Unaudited)

 

 

 

For the Three Months

 

 

 

Ended March 31,

 

 

 

2012

 

2011

 

 

 

(In thousands, except per share data)

 

Revenues:

 

 

 

 

 

Gas sales

 

$

85,153

 

$

131,323

 

Oil sales

 

267,084

 

220,499

 

NGL sales

 

59,014

 

62,190

 

Gas gathering, processing and other

 

11,707

 

12,517

 

Gas marketing, net

 

78

 

67

 

 

 

423,036

 

426,596

 

Costs and expenses:

 

 

 

 

 

Depreciation, depletion and amortization

 

118,262

 

85,026

 

Asset retirement obligation

 

3,525

 

1,938

 

Production

 

67,625

 

58,480

 

Transportation

 

15,606

 

13,446

 

Gas gathering and processing

 

2,561

 

4,551

 

Taxes other than income

 

25,160

 

33,597

 

General and administrative

 

14,147

 

14,727

 

Stock compensation, net

 

4,534

 

4,750

 

Loss on derivative instruments, net

 

4,088

 

18,244

 

Other operating, net

 

2,340

 

3,374

 

 

 

257,848

 

238,133

 

 

 

 

 

 

 

Operating income

 

165,188

 

188,463

 

 

 

 

 

 

 

Other (income) and expense:

 

 

 

 

 

Interest expense

 

8,668

 

8,980

 

Capitalized interest

 

(7,804

)

(7,225

)

Other, net

 

(4,726

)

(604

)

 

 

 

 

 

 

Income before income tax

 

169,050

 

187,312

 

Income tax expense

 

62,943

 

69,150

 

 

 

 

 

 

 

Net income

 

$

106,107

 

$

118,162

 

 

 

 

 

 

 

Earnings per share to common stockholders:

 

 

 

 

 

Basic

 

 

 

 

 

Distributed

 

$

0.12

 

$

0.10

 

Undistributed

 

1.12

 

1.28

 

 

 

$

1.24

 

$

1.38

 

 

 

 

 

 

 

Diluted

 

 

 

 

 

Distributed

 

$

0.12

 

$

0.10

 

Undistributed

 

1.11

 

1.27

 

 

 

$

1.23

 

$

1.37

 

 

 

 

 

 

 

Comprehensive income:

 

 

 

 

 

Net income

 

$

106,107

 

$

118,162

 

Other comprehensive income:

 

 

 

 

 

Change in fair value of investments, net of tax

 

399

 

159

 

Total comprehensive income

 

$

106,506

 

$

118,321

 

 

See accompanying notes to consolidated financial statements.

 

5



Table of Contents

 

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

 

 

 

For the Three Months

 

 

 

Ended March 31,

 

 

 

2012

 

2011

 

 

 

(In thousands)

 

Cash flows from operating activities:

 

 

 

 

 

Net income

 

$

106,107

 

$

118,162

 

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

 

 

 

 

 

Depreciation, depletion and amortization

 

118,262

 

85,026

 

Asset retirement obligation

 

3,525

 

1,938

 

Deferred income taxes

 

62,943

 

69,698

 

Stock compensation, net

 

4,534

 

4,750

 

Derivative instruments, net

 

4,088

 

20,278

 

Changes in non-current assets and liabilities

 

2,239

 

2,738

 

Other, net

 

1,258

 

2,030

 

Changes in operating assets and liabilities:

 

 

 

 

 

(Increase) decrease in receivables, net

 

(2,144

)

2,022

 

(Increase) decrease in other current assets

 

69

 

(3,005

)

Decrease in accounts payable and accrued liabilities

 

(48,989

)

(38,360

)

Net cash provided by operating activities

 

251,892

 

265,277

 

Cash flows from investing activities:

 

 

 

 

 

Oil and gas expenditures

 

(398,103

)

(310,182

)

Sales of oil and gas and other assets

 

1,322

 

12,037

 

Other expenditures

 

(13,160

)

(24,506

)

Net cash used by investing activities

 

(409,941

)

(322,651

)

Cash flows from financing activities:

 

 

 

 

 

Net increase in bank debt

 

167,000

 

 

Dividends paid

 

(8,576

)

(6,849

)

Issuance of common stock and other

 

1,625

 

4,243

 

Net cash provided by (used in) financing activities

 

160,049

 

(2,606

)

Net change in cash and cash equivalents

 

2,000

 

(59,980

)

Cash and cash equivalents at beginning of period

 

2,406

 

114,126

 

Cash and cash equivalents at end of period

 

$

4,406

 

$

54,146

 

 

See accompanying notes to consolidated financial statements.

 

6



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

March 31, 2012

(Unaudited)

 

1.              Basis of Presentation

 

The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in annual reports on Form 10-K have been omitted.  Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our 2011 Annual Report on Form 10-K.

 

In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods shown.  Certain amounts in prior years’ financial statements have been reclassified to conform to the 2012 financial statement presentation.  We have evaluated subsequent events through the date of this filing.

 

Oil and Gas Properties

 

We use the full cost method of accounting for our oil and gas operations.  Accounting rules require us to perform a quarterly analysis of the carrying value of our oil and gas properties for possible impairment.  The primary components impacting this analysis are commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense.  Holding all factors constant, other than commodity prices, a 10% decline in prices at March 31, 2012 would not have resulted in an impairment.

 

However, if prices decrease significantly, we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

 

Use of Estimates

 

The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved oil and gas reserves, the use of these oil and gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations and estimates of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill.  Estimates and judgments are also required in determining reserves for bad debt, impairments of undeveloped properties and other assets, purchase price allocation, valuation of deferred tax assets, fair value measurements and commitments and contingencies.

 

Accounts Receivable, Accounts Payable, and Accrued Liabilities

 

The components of our receivable accounts, accounts payable, and accrued liabilities are shown below.

 

7



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

 

 

March 31,
2012

 

December 31,
2011

 

 

 

(in thousands)

 

Receivables, net of allowance

 

 

 

 

 

Trade

 

$

79,331

 

$

58,519

 

Oil and gas sales

 

229,880

 

245,681

 

Gas gathering, processing, and marketing

 

5,503

 

7,565

 

Other

 

46,839

 

47,644

 

Receivables, net

 

$

361,553

 

$

359,409

 

 

 

 

 

 

 

Accounts payable

 

 

 

 

 

Trade

 

$

50,229

 

$

64,856

 

Gas gathering, processing, and marketing

 

11,233

 

14,932

 

Accounts payable

 

$

61,462

 

$

79,788

 

 

 

 

 

 

 

Accrued liabilities

 

 

 

 

 

Exploration and development

 

$

174,050

 

$

173,549

 

Taxes other than income

 

19,608

 

33,946

 

Other

 

171,146

 

178,156

 

Accrued liabilities

 

$

364,804

 

$

385,651

 

 

Recently Issued Accounting Standards

 

No significant accounting standards applicable to Cimarex have been issued during the quarter ended March 31, 2012.

 

The Financial Accounting Standards Board (“FASB”) issued new accounting guidance which eliminates the option to present other comprehensive income and its components in the statement of changes in equity.  The new guidance requires comprehensive income to be reported in either a single statement that presents the components of net income, the components of other comprehensive income and total comprehensive income, or in two consecutive statements.  We adopted this financial statement presentation requirement effective January 1, 2012 with retrospective application to all prior periods presented.

 

2.              Derivative Instruments/Hedging

 

We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity prices and the corresponding negative impact on cash flow available for reinvestment.  While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes.

 

For 2012 and 2013, management has been authorized to hedge up to 50% of our anticipated equivalent oil and gas production.  Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our current hedging positions.

 

At March 31, 2012, we had the following outstanding contracts relative to our future production.  We have elected not to account for these derivatives as cash flow hedges.

 

Oil Contracts

 

 

 

 

 

 

 

 

 

Weighted Average Price

 

Fair Value

 

Period

 

Type

 

Volume/Day

 

Index(1)

 

Floor

 

Ceiling

 

(000’s)

 

Apr 12 - Dec 12

 

Collar

 

14,000  Bbls

 

WTI

 

$

80.00

 

$

119.35

 

$

(4,333

)

 


(1)         WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

 

8



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

We have hedged about half of our anticipated oil production for 2012.  We do not have any of our gas or NGL production hedged.

 

Under a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor.  We pay the difference between the ceiling price and the index price only if the index price is above the contracted ceiling price.  No amounts are paid or received if the index price is between the floor and ceiling prices.

 

Our derivative contracts are carried at their fair value on our balance sheet.  We estimate the fair value using internal risk adjusted discounted cash flow calculations.  Cash flows are based on published forward commodity price curves for the underlying commodity as of the date of the estimate.  For collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms.

 

The fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk, and the fair value of instruments in a liability position includes a measure of our own nonperformance risk.  These credit risks are based on current published credit default swap rates.

 

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price.  The following tables present the estimated fair value of our derivatives as of March 31, 2012 and December 31, 2011.

 

 

 

Balance Sheet Location

 

Asset

 

Liability

 

 

 

 

 

(In thousands)

 

March 31, 2012:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil contracts

 

Current liabilities — Derivative instruments

 

$

 

$

4,333

 

 

 

 

Balance Sheet Location

 

Asset

 

Liability

 

 

 

 

 

(In thousands)

 

December 31, 2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil contracts

 

Current liabilities — Derivative instruments

 

$

 

$

245

 

 

Because we have elected not to account for our current derivative contracts as cash flow hedges, we recognize all realized settlements and unrealized changes in fair value in earnings.  Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows.

 

The following table summarizes the realized and unrealized gains and losses from settlements and changes in fair value of our derivative contracts as presented in our accompanying financial statements.

 

9



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

Settlements gains (losses):

 

 

 

 

 

Natural gas contracts

 

$

 

$

2,034

 

Oil contracts

 

 

 

Total settlements gains (losses)

 

 

2,034

 

 

 

 

 

 

 

Unrealized gains (losses) from change in fair value:

 

 

 

 

 

Natural gas contracts

 

 

(1,756

)

Oil contracts

 

(4,088

)

(18,522

)

Total net unrealized gains (losses) from change in fair value

 

(4,088

)

(20,278

)

Gain (loss) on derivative instruments, net

 

$

(4,088

)

$

(18,244

)

 

We are exposed to financial risks associated with these contracts from nonperformance by our counterparties.  Counterparty risk is also a component of our estimated fair value calculations.  We have mitigated our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank credit facility.  Our member banks do not require us to post collateral for our hedge liability positions.

 

3.              Fair Value Measurements

 

The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.  This hierarchy consists of three broad levels.  Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities.  Level 2 inputs are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly.  Level 3 inputs are unobservable inputs for an asset or liability.

 

The following tables provide fair value measurement information for certain assets and liabilities as of March 31, 2012 and December 31, 2011.

 

 

 

Carrying
Amount

 

Fair
Value

 

 

 

(In thousands)

 

March 31, 2012:

 

 

 

 

 

 

 

 

 

 

 

Financial Assets (Liabilities):

 

 

 

 

 

Bank debt

 

$

(222,000

)

$

(222,000

)

7.125% Notes due 2017

 

$

(350,000

)

$

(362,600

)

Derivative instruments — liabilities

 

$

(4,333

)

$

(4,333

)

 

 

 

Carrying
Amount

 

Fair
Value

 

 

 

(In thousands)

 

December 31, 2011:

 

 

 

 

 

 

 

 

 

 

 

Financial Assets (Liabilities):

 

 

 

 

 

Bank Debt

 

$

(55,000

)

$

(55,000

)

7.125% Notes due 2017

 

$

(350,000

)

$

(366,772

)

Derivative instruments — liabilities

 

$

(245

)

$

(245

)

 

Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability.  The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above.

 

10



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

Debt

 

The fair value of our bank debt at March 31, 2012 and December 31, 2011 was estimated to approximate the carrying amount because the floating rate interest paid on such debt was set for periods of three months or less.

 

The fair value for our 7.125% fixed rate notes was based on their last traded value before period end.

 

Derivative Instruments (Level 2)

 

The fair value of our derivative instruments was estimated using internal discounted cash flow calculations.  Cash flows are based on the stated contract prices and current and published forward commodity price curves, adjusted for volatility.  The cash flows are risk adjusted relative to nonperformance for both our counterparties and our liability positions.  Please see Note 2 for further information on the fair value of our derivative instruments.

 

Other Financial Instruments

 

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.  At both March 31, 2012 and December 31, 2011, the aggregate allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $6.4 million.

 

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry.  Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.

 

4.              Capital Stock

 

A summary of our common stock activity for the three months ended March 31, 2012 follows (in thousands):

 

Issued and outstanding as of December 31, 2011

 

85,774

 

Restricted shares issued under compensation plans, net of reacquired stock and cancellations

 

(98

)

Option exercises, net of cancellations

 

42

 

Issued and outstanding as of March 31, 2012

 

85,718

 

 

Dividends

 

In February 2012, the Board of Directors increased our quarterly dividend to $0.12 per share from $0.10 per share.  The dividend is payable on June 1, 2012 to stockholders of record on May 15, 2012.  Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other factors considered relevant by the Board of Directors.

 

11



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

5.              Stock-based Compensation

 

Our 2011 Equity Incentive Plan (the “2011 Plan”) was approved by stockholders in May 2011.  The 2011 Plan replaces the 2002 Stock Incentive Plan (the “2002 Plan”).  No new grants will be made under the 2002 Plan.  The 2011 Plan provides for the grant of stock options, restricted stock, restricted stock units, performance stock and performance stock units to officers, other eligible employees and nonemployee directors.  A total of 5.3 million shares of common stock may be issued under the 2011 Plan.

 

The 2011 Plan is modeled after the 2002 Plan, with two major changes:  we have reduced the maximum term of any option granted under the 2011 Plan from ten years to seven years, and dividends will be accrued on all shares subject to performance awards and will only be paid at the time of vesting of the award, and then only with respect to shares that are issued upon attainment of the performance goals.  Service-based restricted awards will continue to receive dividends on unvested shares.

 

We have recognized non-cash stock-based compensation cost as follows (in thousands):

 

 

 

Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Restricted stock and units

 

$

6,821

 

$

6,524

 

Stock options

 

793

 

1,065

 

 

 

7,614

 

7,589

 

Less amounts capitalized to oil and gas properties

 

(3,080

)

(2,839

)

Compensation expense

 

$

4,534

 

$

4,750

 

 

Historical amounts may not be representative of future amounts as additional awards may be granted.

 

Restricted Stock and Units

 

The following table provides information about restricted stock awards granted during 2012 and 2011.  No restricted unit awards were granted during the noted periods.

 

 

 

Three Months Ended
March 31, 2012

 

Three Months Ended
March 31, 2011

 

 

 

Number
of Shares

 

Weighted
Average
Grant-Date
Fair Value

 

Number of
Shares

 

Weighted
Average
Grant-Date
Fair Value

 

Performance-based stock awards

 

 

$

 

363,758

 

$

73.01

 

Service-based stock awards

 

18,500

 

$

60.49

 

14,500

 

$

104.73

 

Total restricted stock awards

 

18,500

 

$

60.49

 

378,258

 

$

74.23

 

 

The performance-based awards were issued to certain executive officers and are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance.  After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award.  In accordance with Internal Revenue Code Section 162(m), certain of the amounts awarded may not be deductible for tax purposes.  The material terms of performance goals applicable to these awards were approved by stockholders in May 2010.  The other restricted shares granted in 2012 and 2011 have service-based vesting schedules of five years.

 

12



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

A restricted unit represents a right to an unrestricted share of common stock upon satisfaction of defined vesting and holding conditions.  Restricted units have a five-year vesting schedule and an additional three-year holding period following vesting, prior to payment in common stock.

 

Compensation cost for the performance-based stock awards is based on the grant date fair value of the award utilizing a Monte Carlo simulation model.  Compensation cost for the service-based vesting restricted shares and units is based upon the grant-date market value of the award.  Such costs are recognized ratably over the applicable vesting period.

 

The following table reflects the non-cash compensation cost related to our restricted stock and units (in thousands):

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

Performance-based stock awards

 

$

3,589

 

$

3,991

 

Service-based stock awards

 

3,232

 

2,511

 

Restricted unit awards

 

 

22

 

 

 

6,821

 

6,524

 

Less amounts capitalized to oil and gas properties

 

(2,730

)

(2,190

)

Restricted stock and units compensation expense

 

$

4,091

 

$

4,334

 

 

Unamortized compensation cost related to unvested restricted shares and units at March 31, 2012 was $56.2 million, which we expect to recognize over a weighted average period of approximately 2 years.

 

The following table provides information on restricted stock and unit activity as of March 31, 2012 and changes during the year:

 

 

 

Restricted
Stock

 

Restricted
Units

 

Outstanding as of January 1, 2012

 

2,019,552

 

59,470

 

Vested

 

(237,000

)

 

Converted to stock

 

 

(632

)

Granted

 

18,500

 

 

Canceled

 

(19,850

)

 

Outstanding as of March 31, 2012

 

1,781,202

 

58,838

 

Vested included in outstanding

 

N/A

 

58,838

 

 

Stock Options

 

Options granted under our 2011 and 2002 plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years.  The plans provide that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant.  No options were granted during the first quarters of 2012 and 2011.

 

Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period.  We estimate the fair value using the Black-Scholes option-pricing model.  Expected volatilities are based on the historical volatility of our common stock.  We also use historical data to estimate the probability of option exercise, expected years until exercise

 

13



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

and potential forfeitures.  We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.

 

Non-cash compensation cost related to our stock options is reflected in the following table (in thousands):

 

 

 

Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Stock option awards

 

$

793

 

$

1,065

 

Less amounts capitalized to oil and gas properties

 

(350

)

(649

)

Stock option compensation expense

 

$

443

 

$

416

 

 

As of March 31, 2012, there was $4.6 million of unrecognized compensation cost related to non-vested stock options.  We expect to recognize that cost pro rata over a weighted-average period of approximately 2 years.

 

Information about outstanding stock options is summarized below:

 

 

 

Options

 

Weighted
Average
Exercise
Price

 

Weighted
Average
Remaining
Term

 

Aggregate
Intrinsic
Value
(000’s)

 

Outstanding as of January 1, 2012

 

1,113,334

 

$

37.94

 

 

 

 

 

Exercised

 

(42,075

)

$

50.32

 

 

 

 

 

Granted

 

 

$

 

 

 

 

 

Forfeited

 

(6,403

)

$

68.23

 

 

 

 

 

Outstanding as of March 31, 2012

 

1,064,856

 

$

37.27

 

3.9 Years

 

$

41,495

 

Exercisable as of March 31, 2012

 

764,514

 

$

28.10

 

2.7 Years

 

$

36,120

 

 

The following table provides information regarding the options exercised (dollars in thousands):

 

 

 

Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Number of options exercised

 

42,075

 

36,193

 

Cash received from option exercises

 

$

2,117

 

$

1,432

 

Tax benefit from option exercises included in paid-in-capital

 

$

(1)

$

797

 

Intrinsic value of options exercised

 

$

1,261

 

$

2,185

 

 


(1) No tax benefit is recorded until the benefit reduces current taxes payable.

 

The following summary reflects the status of non-vested stock options as of March 31, 2012 and changes during the year:

 

 

 

Options

 

Weighted
Average
Grant-Date
Fair Value

 

Weighted
Average
Exercise
Price

 

Non-vested as of January 1, 2012

 

308,411

 

$

23.37

 

$

60.75

 

Vested

 

(1,666

)

$

24.61

 

$

62.07

 

Forfeited

 

(6,403

)

$

27.47

 

$

68.23

 

Non-vested as of March 31, 2012

 

300,342

 

$

23.28

 

$

60.59

 

 

14



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

6.              Asset Retirement Obligations

 

We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.  Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well.  Subsequent to initial measurement, the asset retirement liability is required to be accreted each period.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost.  Capitalized costs are depleted as a component of the full cost pool.

 

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the three months ended March 31, 2012 (in thousands):

 

Asset retirement obligation at January 1, 2012

 

$

183,361

 

Liabilities incurred

 

1,106

 

Liability settlements and disposals

 

(7,119

)

Accretion expense

 

2,473

 

Revisions of estimated liabilities

 

2,639

 

Asset retirement obligation at March 31, 2012

 

182,460

 

Less current obligation

 

(42,911

)

Long-term asset retirement obligation

 

$

139,549

 

 

7.              Long-Term Debt

 

Debt at March 31, 2012 and December 31, 2011 consisted of the following (in thousands):

 

 

 

March 31,
2012

 

December 31,
2011

 

Bank debt

 

$

222,000

 

$

55,000

 

7.125% Senior Notes due 2017

 

350,000

 

350,000

 

Total long-term debt

 

$

572,000

 

$

405,000

 

 

In April, 2012 we issued $750 million of 5.875% senior notes due 2022, with interest payable semiannually in May and November.  The notes were sold to the public at par.  We may redeem the notes in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and thereafter.

 

Net proceeds from the offering approximated $737 million, after deducting underwriting discounts, commissions and estimated expenses of the offering.  We will use a portion of the net proceeds to retire our 7.125% senior notes.  The remaining net proceeds will be used for general corporate purposes, including repayment of amounts outstanding under our revolving credit facility.

 

Bank Debt

 

We have a five-year senior unsecured revolving credit facility (“Credit Facility”).  The Credit Facility provides for a borrowing base of $2 billion with aggregate commitments of $800 million from 14 lenders.  The facility matures July 14, 2016.

 

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Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

The borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves.  Our borrowing base of $2 billion was reaffirmed by the lenders in April, 2012.  The next regular annual redetermination date is on April 15, 2013.

 

At Cimarex’s option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio.

 

The Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0.  We also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0.  Other covenants could limit our ability to: incur additional indebtedness, pay dividends, repurchase our common stock, or sell assets.  As of March 31, 2012, we were in compliance with all of the financial and nonfinancial covenants.

 

As of March 31, 2012, there were $222 million of borrowings outstanding under the Credit Facility at a prime rate of 4%.  We also had letters of credit outstanding of $2.5 million leaving an unused borrowing availability of $575.5 million.

 

7.125% Notes due 2017

 

In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par.  Interest on the notes is payable May 1 and November 1 of each year.  The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions.  The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at 103.563% of the principal amount as of May 1, 2012, declining to 100% on May 1, 2015 and thereafter.

 

On March 22, 2012 we commenced a cash tender offer (the “Tender Offer”) to purchase all of the outstanding 7.125% senior notes.  Under the terms of the Tender Offer, holders who tendered their notes prior to the deadline on April 4, 2012 would receive (i) $1,035.63 per $1,000.00 in principal amount of notes tendered plus (ii) a consent payment of $3.75 per $1,000.00 in principal amount of notes tendered.  Holders tendering their notes after April 4, 2012 but prior to expiration of the Tender Offer on April 18, 2012 would not be eligible for the consent payment.  Through April 18, 2012 a total of $300,163,000 of notes had been redeemed.  We intend to call for redemption, in May 2012, the remaining $49,837,000 of notes that were not tendered.

 

In connection with the Tender Offer, holders who tendered their notes were deemed to consent to proposed amendments to eliminate or modify certain covenants and events of default and other provisions contained in the indenture governing the 7.125% senior notes.

 

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Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

8.              Income Taxes

 

The components of our provision for income taxes are as follows (in thousands):

 

 

 

Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Current provision (benefit)

 

$

 

$

(548

)

Deferred tax expense

 

62,943

 

69,698

 

 

 

$

62,943

 

$

69,150

 

 

At December 31, 2011 the company had a U.S. net tax operating carryforward of approximately $107 million which would expire in 2031.  We believe that the carryforward will be utilized before it expires.  We also had an alternative minimum tax credit carryfoward of approximately $2.9 million.

 

At March 31, 2012 we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions.  The tax years 2005-2011 remain open to examination by the Internal Revenue Service of the United States.  We file tax returns with various state taxing authorities which remain open for tax years 2005-2011 for examination.

 

Our provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and nondeductible expenses. The effective income tax rate for the three months ended March 31, 2012 and March 31, 2011 was 37.2% and 36.9%, respectively.

 

9.              Supplemental Disclosure of Cash Flow Information (in thousands):

 

 

 

Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Cash paid during the period for:

 

 

 

 

 

Interest expense (including capitalized amounts)

 

$

1,759

 

$

1,062

 

Interest capitalized

 

1,584

 

854

 

Income taxes

 

11

 

171

 

Cash received for income taxes

 

816

 

25,004

 

 

17



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

10.       Earnings per Share

 

The calculations of basic and diluted net earnings per common share under the two-class method are presented below (in thousands, except per share data):

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

Net income

 

$

106,107

 

$

118,162

 

Less distributed earnings (dividends declared during the period)

 

(10,296

)

(8,561

)

Undistributed earnings for the period

 

$

95,811

 

$

109,601

 

 

 

 

 

 

 

Allocation of undistributed earnings

 

 

 

 

 

Basic allocation to unrestricted common stockholders

 

$

93,756

 

$

106,938

 

Basic allocation to participating securities

 

$

2,055

 

$

2,663

 

Diluted allocation to unrestricted common stockholders

 

$

93,765

 

$

106,952

 

Diluted allocation to participating securities

 

$

2,046

 

$

2,649

 

 

 

 

 

 

 

Basic Shares Outstanding

 

 

 

 

 

Unrestricted outstanding common shares

 

83,937

 

83,546

 

Add participating securities:

 

 

 

 

 

Restricted stock outstanding

 

1,781

 

1,994

 

Restricted stock units outstanding

 

59

 

86

 

Total participating securities

 

1,840

 

2,080

 

Total Basic Shares Outstanding

 

85,777

 

85,626

 

 

 

 

 

 

 

Fully Diluted Shares

 

 

 

 

 

Unrestricted outstanding common shares

 

83,937

 

83,546

 

Incremental shares from assumed exercise of stock options

 

370

 

438

 

Fully diluted common stock

 

84,307

 

83,984

 

Participating securities

 

1,840

 

2,080

 

Total Fully Diluted Shares

 

86,147

 

86,064

 

 

 

 

 

 

 

Basic earnings per share

 

 

 

 

 

Unrestricted common stockholders:

 

 

 

 

 

Distributed earnings

 

$

0.12

 

$

0.10

 

Undistributed earnings

 

1.12

 

1.28

 

 

 

$

1.24

 

$

1.38

 

Participating securities:

 

 

 

 

 

Distributed earnings

 

$

0.12

 

$

0.10

 

Undistributed earnings

 

1.12

 

1.28

 

 

 

$

1.24

 

$

1.38

 

Fully diluted earnings per share

 

 

 

 

 

Unrestricted common stockholders:

 

 

 

 

 

Distributed earnings

 

$

0.12

 

$

0.10

 

Undistributed earnings

 

1.11

 

1.27

 

 

 

$

1.23

 

$

1.37

 

Participating securities:

 

 

 

 

 

Distributed earnings

 

$

0.12

 

$

0.10

 

Undistributed earnings

 

1.11

 

1.27

 

 

 

$

1.23

 

$

1.37

 

 

The following table presents the amounts of outstanding stock options, restricted stock and units:

 

 

 

March 31,

 

 

 

2012

 

2011

 

Stock options

 

1,064,856

 

982,499

 

Restricted stock

 

1,781,202

 

1,993,781

 

Restricted units

 

58,838

 

86,470

 

 

18



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

Certain stock options considered to be anti-dilutive for the three months ended March 31, 2012 and 2011 were 167,467 and 9,228, respectively.

 

11.       Commitments and Contingencies

 

Litigation

 

H.B. Krug, et al versus H&P

 

In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus Helmerich & Payne, Inc. (“H&P”) case.  This lawsuit was originally filed in 1998 and addressed H&P’s conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters.  Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P’s exploration and production business.  In 2008 we recorded litigation expense of $119.6 million for this lawsuit.  We have accrued additional expense for associated post-judgment interest and costs that have accrued during the appeal of the District Court’s judgments.

 

On August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation.  The Oklahoma Court of Appeals reversed and remanded the $112.7 million disgorgement of profits award, finding the District Court erred in failing to make the required findings of fact and conclusions of law.  In all other respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million.  On October 27, 2011, Cimarex filed a petition with the Oklahoma Supreme Court requesting review of the affirmed portion of the judgment.  This case is subject to further appeal and the final outcome cannot be determined at this time.  If the District Court’s original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then determined amount of post-judgment interest and costs would become payable.

 

The following table reflects the change in the accrued liability for this lawsuit for the three months ended March 31, 2012 (in thousands):

 

Outstanding at January 1, 2012

 

$

146,310

 

Accrued post-judgment interest and costs

 

2,256

 

Outstanding at March 31, 2012

 

$

148,566

 

 

Other litigation

 

In the normal course of business, we have other various litigation related matters.  We assess the probability of estimable amounts related to litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly.  Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.

 

Other

 

We have drilling commitments of approximately $268.6 million consisting of obligations to finish drilling and completing wells in progress at March 31, 2012.  We also have various commitments for drilling rigs as well as certain service contracts.  The total minimum expenditure commitments under these agreements are $34.4 million to secure the use of drilling rigs and $21.5 million to secure certain dedicated services associated with completion activities.

 

19



Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

 

We have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines.  At March 31, 2012, we had commitments of $9.9 million relating to this construction.

 

At March 31, 2012, we had firm sales contracts to deliver approximately 22.1 Bcf of natural gas over the next 12 months.  If this gas is not delivered, our financial commitment would be approximately $52.3 million.  This commitment will fluctuate due to price volatility and actual volumes delivered.  However, we believe no financial commitment will be due based on our current reserves and production levels.

 

We have other various transportation and delivery commitments in the normal course of business, which approximate $8.3 million.

 

All of the noted commitments were routine and were made in the normal course of our business.

 

12.      Property Sales and Acquisitions

 

There were no significant property sales during the first quarter of 2012.  During the first quarter of 2011, we sold various interests in oil and gas properties for approximately $11.8 million.  We had no significant property acquisitions during the first quarters of 2012 and 2011.

 

We intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our Cana-Woodford shale play and in the Permian Basin.

 

20



Table of Contents

 

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

 

OVERVIEW

 

We are an independent oil and gas exploration and production company.  Our operations are entirely located in the United States, mainly in Oklahoma, New Mexico, Texas and Kansas.

 

Our principle business objective is to achieve profitable growth in proved reserves and production for the long-term benefit of our shareholders, primarily through exploration and development.  Our strategy centers on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development drilling.

 

To supplement our growth and to provide for new drilling opportunities, we also consider property acquisitions and mergers that allow us to enhance our competitive position in existing core areas or to add new areas.  In order to achieve a consistent rate of growth and mitigate risk we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development projects.  To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins.  We intend to deal with volatility in the current commodity price environment by maintaining flexibility in our planned capital investment program for 2012.

 

Our operations are currently focused in two main areas:  the Mid-Continent region and the Permian Basin.  The Mid-Continent region consists of Oklahoma, northern Texas and southwest Kansas.  Our Permian Basin region encompasses west Texas and southeast New Mexico.  We also have operations in the Gulf Coast area, primarily in southeast Texas.

 

Our growth is generally funded with cash flow provided by our operating activities together with occasional sales of non-strategic assets.  Conservative use of leverage has long been a part of our financial strategy.

 

Our revenue, profitability and future growth are highly dependent on the commodity prices we receive.  Oil and gas prices affect the amount of cash flow available for capital expenditures, our ability to raise additional capital and the fair market value of our assets.  We use the full cost method of accounting for oil and gas activities.  Any extended decline in oil and gas prices could have an adverse effect on our financial position and results of operations, including the determination of full-cost accounting ceiling test writedowns.

 

The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities, equity and proved reserves.

 

First quarter 2012 summary operating and financial results:

 

·                  First quarter production volumes averaged 603.5 MMcfe per day, up 2% from 590.0 MMcfe per day for first quarter 2011.

 

·                  Oil, gas and NGL sales for the first quarter of 2012 were $411.3 million, compared to $414.0 million a year earlier.

 

·                  Our average realized oil price increased 9% to $99.28 per barrel compared to $91.46 per barrel in 2011.

 

·                  Our average realized gas price decreased 34% to $2.92 per Mcf versus $4.45 per Mcf in 2011.

 

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·                  Our average realized NGL price decreased 10% to $36.66 per barrel compared to $40.77 per barrel in 2011

 

·                  Our first quarter cash flow from operating activities was $251.9 million versus $265.3 million in the prior year.

 

·                  Net income of $106.1 million ($1.23 per diluted share) declined from net income of $118.2 million ($1.37 per diluted share) in 2011.

 

·                  Total debt increased by $167 million to $572 million compared to $405 million at year-end 2011.

 

·                  We drilled and completed 73 gross (40 net) wells during the first quarter of 2012 compared to 67 gross (36.7 net) wells with 65 gross (34.7 net) completed as producers a year earlier.

 

Revenues

 

Our revenues are derived from the sale of our oil, gas and NGL production and do not include the effects of the settlements of our commodity hedging contracts.  While our revenues are a function of both production and prices, wide swings in commodity prices have had the greatest impact on our results of operations.  Compared to 2011, our 2012 average realized gas price decreased by 34% and our average realized NGL price decreased by 10%.  The average price we received for oil increased by 9%.  Since March 31, 2012 gas prices have declined further, primarily as a result of an oversupply.  Like gas, NGL prices have also declined.  Oil prices continue to fluctuate as a result of concerns about economic and geopolitical instability.

 

The following table presents our average realized prices for the first quarter of 2012 compared to the same period of 2011.

 

 

 

Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Gas Prices:

 

 

 

 

 

Average Henry Hub price ($/Mcf)

 

$

2.72

 

$

4.11

 

Average realized sales price ($/Mcf)

 

$

2.92

 

$

4.45

 

Oil Prices:

 

 

 

 

 

Average WTI Cushing price ($/Bbl)

 

$

102.93

 

$

94.15

 

Average realized sales price ($/Bbl)

 

$

99.28

 

$

91.46

 

NGL Prices:

 

 

 

 

 

Average realized sales price ($/Bbl)

 

$

36.66

 

$

40.77

 

 

On an energy equivalent basis, 53% of our first quarter 2012 aggregate production was natural gas.  A $0.10 per Mcf change in our average realized gas sales price would have resulted in a $2.9 million change in our gas revenues.  Similarly, 47% of our production was crude oil and NGL.  A $1.00 per barrel change in our average realized sales price would have resulted in a $4.3 million change in our combined oil and NGL revenues.

 

Production and other operating expenses

 

Costs associated with finding and producing oil and gas are substantial.  Some of these costs vary with commodity prices, some trend with the type and volume of production and some are a function of the number of wells we own.  At the end of 2011, we owned interests in 12,701 gross wells.

 

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Production expense generally consists of the cost of water disposal, power and fuel, direct labor, third-party field services, compression and certain maintenance activity (workovers) necessary to produce oil and gas from existing wells.

 

Transportation expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point.  In some cases we receive a payment from purchasers which is net of transportation costs, and in other instances we separately pay for transportation.  If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and expenses, respectively.

 

Depreciation, depletion and amortization (DD&A) of our producing properties is computed using the units-of-production method.  The economic life of each producing well depends upon the assumed price for future sales of production.  Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation.  Higher prices generally have the effect of increasing reserves, which reduces depletion expense.  Lower prices generally have the effect of decreasing reserves, which increases depletion expense.  In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, and reclassifications from unproved properties to proved properties will impact depletion expense.

 

General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices and not directly associated with exploration, development or production activities.  While we expect these costs to increase with our growth, we also expect such increases to be proportionately smaller than our production growth.

 

Production taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties.  These typically include production severance, ad valorem and excise taxes.

 

Stock compensation expense consists of noncash charges resulting from the issuance of restricted stock, restricted stock units and stock options.  In accordance with our stock incentive plan, such grants are periodically made to nonemployee directors, officers and other eligible employees.

 

The net gain or loss on derivative instruments is the net realized and unrealized gain or loss on derivative contracts, to which we did not apply hedge accounting treatment.  That amount will fluctuate based on changes in the fair value of the underlying commodities.

 

Hedging

 

From time to time, we attempt to mitigate a portion of our price risk through the use of hedging transactions.  Management has been authorized to hedge up to 50% of our anticipated 2012 and 2013 equivalent production.

 

During 2010, we entered into oil and gas contracts relative to our 2011 production which approximated 40 to 45% of our anticipated 2011 oil production and 5 to 6% of projected gas production.  Those contracts had net cash settlements in the first quarter of 2011 of $2.0 million.

 

For 2012, we have hedged about half of our anticipated oil production.  We do not have any of our gas or NGL production hedged.  We had no cash settlements on 2012 contracts in the first quarter of 2012.  We had the following contracts outstanding at March 31, 2012:

 

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Oil Contracts

 

 

 

 

 

 

 

 

 

Weighted
Average Price

 

Period

 

Type

 

Volume/Day

 

Index(1)

 

Floor

 

Ceiling

 

Apr 12 - Dec 12

 

Collar

 

14,000  Bbls

 

WTI

 

$

80.00

 

$

119.35

 

 


(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

 

Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our current hedging positions.  While the use of such instruments limits the downside risk of adverse price changes, this use may also limit future income from favorable price changes.

 

We have chosen not to apply hedge accounting treatment to the derivative contracts we entered into.  Therefore, settlements on our derivative contracts do not impact our realized commodity prices during the periods they cover.  Instead, any settlements on the contracts are shown as a component of operating costs and expenses as either a net gain or loss on derivative instruments.  See Note 2 to the Consolidated Financial Statements and Item 3 of this report for additional information regarding our derivative instruments.

 

RESULTS OF OPERATIONS

 

Quarter ended March 31, 2012 vs. March 31, 2011

 

Net income for the first quarter of 2012 was $106.1 million, or $1.23 per diluted share.  This compares to $118.2 million, or $1.37 per diluted share, for the same period in 2011.  In 2012, increased revenue from higher oil sales was more than offset by lower gas and NGL sales and higher DD&A expense.  A lower net loss on 2012 derivative instruments compared to 2011 partially offset the increase in DD&A expense.  These changes are discussed further in the analysis that follows.

 

 

 

For the Three Months
Ended March 31,

 

Percent
Change
Between

 

Price / Volume Analysis

 

(In thousands or as indicated)

 

2012

 

2011

 

2012/2011

 

Price

 

Volume

 

Variance

 

Gas sales

 

$

85,153

 

$

131,323

 

-35%

 

$

(44,549

)

$

(1,621

)

$

(46,170

)

Oil sales

 

267,084

 

220,499

 

21%

 

21,036

 

25,549

 

46,585

 

NGL Sales

 

59,014

 

62,190

 

-5%

 

(6,617

)

3,441

 

(3,176

)

Total sales

 

$

411,251

 

$

414,012

 

-1%

 

$

(30,130

)

$

27,369

 

$

(2,761

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gas volume—MMcf

 

29,117

 

29,486

 

-1%

 

 

 

 

 

 

 

Gas volume—MMcf per day

 

320.0

 

327.6

 

 

 

 

 

 

 

 

 

Average gas price—per Mcf

 

$

2.92

 

$

4.45

 

-34%

 

 

 

 

 

 

 

Total oil volume—thousand barrels

 

2,690

 

2,411

 

12%

 

 

 

 

 

 

 

Oil volume—barrels per day

 

29,562

 

26,788

 

 

 

 

 

 

 

 

 

Average oil price—per barrel

 

$

99.28

 

$

91.46

 

9%

 

 

 

 

 

 

 

Total NGL volume—thousand barrels

 

1,610

 

1,525

 

6%

 

 

 

 

 

 

 

NGL volume—barrels per day

 

17,687

 

16,947

 

 

 

 

 

 

 

 

 

Average NGL price—per barrel

 

$

36.66

 

$

40.77

 

-10%

 

 

 

 

 

 

 

 

Commodity sales for the first quarter of 2012 totaled $411.3 million, compared to $414.0 million in 2011.  Increased oil sales of $46.6 million during 2012 were more than offset by lower realized sales prices for natural gas and NGL.

 

In 2012, our aggregate production volumes were 603.5 MMcfe per day, up 2% from 590.0 MMcfe per day in 2011.  Production volumes continue to increase from our Permian Basin operations and our Cana-Woodford shale play as a result of our successful drilling programs.  However, these increases

 

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have been offset by decreased Gulf Coast production.  The lower output from the Gulf Coast results from natural declines in wells we drilled in previous years.

 

Our 2012 gas production averaged 320.0 MMcf per day, down slightly from 327.6 MMcf per day in 2011.  This decrease resulted in $1.6 million of lower gas revenue.

 

Oil production for 2012 averaged 29,562 barrels per day, compared to 26,788 barrels per day in 2011.  The increase in oil production resulted in $25.5 million of additional oil revenue in 2012.

 

In 2012 our average daily NGL production was 17,687 barrels per day, compared to 16,947 barrels per day for 2011.  The increase in NGL volume added $3.4 million of revenue.

 

Our average realized gas price for 2012 fell to $2.92 per Mcf, compared to $4.45 per Mcf in 2011.  The 34% decrease in our realized gas price resulted in $44.5 million of lower gas revenue in 2012.

 

Realized oil prices in 2012 averaged $99.28 per barrel, an increase of 9% over the average price received for oil in 2011 of $91.46.  This increase resulted in an additional $21.0 million of oil sales in 2012.

 

The average NGL price we received in 2012 was $36.66 per barrel, down from $40.77 per barrel in 2011.  The decrease in the NGL price resulted in lower NGL sales of $6.6 million.

 

 

 

For the Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Gas Gathering, Processing, Marketing and Other (in thousands):

 

 

 

 

 

Gas gathering, processing and other revenues

 

$

11,707

 

$

12,517

 

Gas gathering and processing costs

 

(2,561

)

(4,551

)

Gas gathering, processing and other margin

 

$

9,146

 

$

7,966

 

 

 

 

 

 

 

Gas marketing revenues, net of related costs

 

$

78

 

$

67

 

 

We sometimes transport, process and market third-party gas that is associated with our gas.  In the first quarter of 2012, third-party gas gathering, processing and other contributed $9.1 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $8.0 million in 2011.  Our gas marketing margin (revenues less purchases) increased to $78 thousand in the first quarter of 2012 from $67 thousand in the first quarter of 2011.  Changes in net margins from gas gathering, processing, marketing and other activities are the direct result of volumetric changes and overall market conditions.

 

 

 

For the Three Months
Ended March 31,

 

Variance
Between

 

 

 

2012

 

2011

 

2012/2011

 

Operating Costs and Expenses (In thousands):

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

$

118,262

 

$

85,026

 

$

33,236

 

Asset retirement obligation

 

3,525

 

1,938

 

1,587

 

Production

 

67,625

 

58,480

 

9,145

 

Transportation

 

15,606

 

13,446

 

2,160

 

Taxes other than income

 

25,160

 

33,597

 

(8,437

)

General and administrative

 

14,147

 

14,727

 

(580

)

Stock compensation, net

 

4,534

 

4,750

 

(216

)

(Gain) loss on derivative instruments, net

 

4,088

 

18,244

 

(14,156

)

Other operating, net

 

2,340

 

3,374

 

(1,034

)

 

 

$

255,287

 

$

233,582

 

$

21,705

 

 

Total operating costs and expenses (not including gas gathering, marketing, and processing costs or income tax expense) increased $21.7 million to $255.3 million for the first quarter of 2012 compared to

 

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$233.6 million in the first quarter of 2011.  Analyses of the quarter over quarter differences are discussed below.

 

DD&A increased 39% from $85.0 million in the first quarter of 2011 to $118.3 million in the same period of 2012.  On a unit of production basis, DD&A was $2.15 per Mcfe in 2012 compared to $1.60 per Mcfe for 2011.  The increase in DD&A is primarily the result of increasing the cost of reserves added at a greater rate than the increase in future production.

 

Production costs rose 16% from $58.5 million ($1.10 per Mcfe) in the first quarter of 2011 to $67.6 million ($1.23 per Mcfe) in the first quarter of 2012.  Our production costs consist of lease operating expense and workover expense as follows (in thousands):

 

 

 

For the Three Months
Ended March 31,

 

Variance
Between

 

 

 

2012

 

2011

 

2012/2011

 

Lease operating expense

 

$

56,552

 

$

49,950

 

$

6,602

 

Workover expense

 

11,073

 

8,530

 

2,543

 

 

 

$

67,625

 

$

58,480

 

$

9,145

 

 

About 60% of the $6.6 million increase in our lease operating expense relates to higher water disposal costs associated with wells coming on line from our successful Permian Basin and Cana-Woodford shale drilling programs.  Increased costs for labor and supplies have also contributed to the increase in 2012.  Workover expense for 2012 was $2.5 million higher than 2011 due to more activity being necessary in 2012.

 

Transportation costs rose to $15.6 million ($0.28 per Mcfe) for 2012 from $13.4 million ($0.25 per Mcfe) in 2011.  Transportation costs will fluctuate regionally, based on increases or decreases in sales volumes, compression charges and fluctuation in the price of the fuel cost component.

 

Taxes other than income decreased 25% from $33.6 million in 2011 to $25.2 million in 2012.  Generally, taxes other than income will vary based on increases or decreases in production volumes and changes in commodity prices.  In addition, the first quarter of 2012 benefited from certain horizontal drilling and deep well tax credits.

 

Stock compensation expense, net consists of noncash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards net of amounts capitalized.  We have recognized noncash stock-based compensation cost as follows (in thousands):

 

 

 

For the Three Months
Ended March 31,

 

Variance
Between

 

 

 

2012

 

2011

 

2012/2011

 

Performance-based restricted stock awards

 

$

3,589

 

$

3,991

 

$

(402

)

Service-based restricted stock awards

 

3,232

 

2,511

 

721

 

Restricted unit awards

 

 

22

 

(22

)

Restricted stock and units

 

6,821

 

6,524

 

297

 

Stock option awards

 

793

 

1,065

 

(272

)

Total stock compensation

 

7,614

 

7,589

 

25

 

Less amounts capitalized to oil and gas properties

 

(3,080

)

(2,839

)

(241

)

Stock compensation, net

 

$

4,534

 

$

4,750

 

$

(216

)

 

Expense associated with stock compensation will fluctuate based on the grant-date market value of the award and the number of awards granted.  See Note 5 to the Consolidated Financial Statements for further discussion regarding our stock-based compensation.

 

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Our net (gain) or loss on derivative instruments includes both realized gains and losses on settlements of our derivative contracts and unrealized gains and losses stemming from changes in the fair value of our outstanding derivative instruments.

 

We estimate the fair value of these instruments based on published forward commodity price curves for the underlying commodity as of the date of the estimate.  For collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms.  The fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk, and the fair value of instruments in a liability position includes a measure of our own nonperformance risk.  These credit risks are based on current published credit default swap rates.

 

We did not elect to use hedge accounting treatment for derivative contracts outstanding in 2012 and 2011.  Therefore we recognized all realized settlements and unrealized changes in fair value in our operating costs and expenses.  The following table reflects our net realized and unrealized (gains) and losses on our derivative instruments (in thousands):

 

 

 

For the Three Months
Ended March 31,

 

Variance
Between

 

 

 

2012

 

2011

 

2012/2011

 

Realized (gain) on settlement of derivative instruments

 

$

 

$

(2,034

)

$

2,034

 

Unrealized loss from changes to the fair value of the derivative instruments

 

4,088

 

20,278

 

$

(16,190

)

Loss on derivative instruments, net

 

$

4,088

 

$

18,244

 

$

(14,156

)

 

Realized and unrealized gains or losses on derivative contracts are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.  See Note 2 to the Consolidated Financial Statements for further details regarding our derivative instruments.

 

Other operating, net expense consists of costs related to various legal matters most of which pertain to litigation and contract settlements and title and royalty issues.

 

Other income and expense

 

Interest expense for the first quarter of 2012 was $8.7 million compared to $9.0 million for the same period of 2011.  Our interest expense includes interest on outstanding borrowings, amortization of financing costs and miscellaneous interest expense.  Our 7.125% senior notes accounted for 72% and 69% of our 2012 and 2011 interest expense, respectively.

 

Components of other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss on the sale or value of oil and gas well equipment, income and expense associated with other non-operating activities, miscellaneous asset sales and interest income.  Other, net increased from $0.6 million of income in the first quarter of 2011 to $4.7 million of income in the first quarter of 2012.  The $4.1 million increase was mainly due to sales of oil and gas well equipment and supplies and income from other non-operating activities.

 

Income tax expense

 

In the first quarter of 2012 we recognized $62.9 million of income tax expense, which did not include any provision for current taxes.  This compares with 2011 first quarter income tax expense of $69.2 million, which included $0.5 million of current tax benefit.  The combined Federal and state effective income tax rates was 37.2% for the first quarter of 2012 compared to 36.9% for the first quarter of 2011.  Our 2012 provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and nondeductible expenses.

 

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LIQUIDITY AND CAPITAL RESOURCES

 

Overview

 

Our liquidity is highly dependent on the commodity prices we receive.  Oil and gas prices are market-driven and historically have been very volatile.  We cannot predict future commodity prices.  The prices we receive for our production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth.

 

Prices for natural gas have continued to decline since year-end 2011, primarily as a result of an oversupply of natural gas and an exceptionally mild winter.  With demand expected to remain low, prices could decline even further.  The prices we receive for oil and NGL may fluctuate during 2012, depending on global supply and demand, seasonality and other geopolitical and economic factors.

 

Historically our exploration and development expenditures have generally been funded by cash flow provided by operating activities (“operating cash flow”).  We expect our 2012 E&D capital expenditures to be funded by operating cash flow, long-term debt and property sales.  We have hedged a portion of our 2012 oil production to protect our operating cash flow for reinvestment.

 

From time to time we consider acquisition opportunities.  However, the timing and size of acquisitions are unpredictable.  To stay prepared for potential acquisitions and possible declines in commodity prices, we have a revolving credit facility, which provides for bank commitments of $800 million.  Our credit facility is described in more detail under “Long-Term Debt” below.

 

At March 31, 2012, our total debt outstanding was $572 million, which is comprised of $222 million of bank debt and $350 million of our 7.125% Notes due in 2017.  Our debt to total capitalization ratio at March 31, 2012 was 15%.  The reconciliation of debt to total capitalization, which is a non-GAAP measure, is:  long-term debt of $572 million divided by long-term debt of $572 million plus stockholders’ equity of $3.230 billion.  Management believes that this non-GAAP measure is useful information and it is a common statistic referred to by the investment community.  Also, see our discussion of “Long-Term Debt” below regarding recent developments related to our debt.

 

We believe that our operating cash flow and other capital resources will be adequate to continue to meet our needs for our planned capital expenditures, working capital, debt servicing and dividend payments for 2012 and beyond.

 

Analysis of Cash Flow Changes

 

Cash flow provided by operating activities for the first quarter of 2012 was $251.9 million, compared to $265.3 million for the same period of 2011.  Most of the $13.4 million decrease was a result of utilizing cash flow in the first quarter of 2012 to reduce accounts payable and accrued liabilities.

 

Cash flow used in investing activities for the first three months of 2012 was $409.9 million, compared to $322.7 million for the three months ended March 31, 2011.  In 2012 we had oil and gas and other capital expenditures of $411.2 million, which were partially offset by $1.3 million of asset sales.  For 2011, expenditures for oil and gas and other capital costs were $334.7 million with proceeds from asset sales of $12.0 million.

 

In the first quarter of 2012 we had net cash flow provided by financing activities of $160.0 million versus cash flow used in financing activities of $2.6 million for the same period of 2011.  The $162.6 million increase in our 2012 net cash inflow was primarily due to net bank borrowings of $167 million during 2012.

 

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Reconciliation of Cash Flow from Operations

 

 

 

For the Three Months
Ended March 31,

 

 

 

2012

 

2011

 

 

 

(In thousands)

 

Net cash provided by operating activities

 

$

251,892

 

$

265,277

 

Change in operating assets and liabilities

 

51,064

 

39,343

 

Cash flow from operations

 

$

302,956

 

$

304,620

 

 

Management believes that the non-GAAP measure of cash flow from operations is useful information for investors because it is used internally and is accepted by the investment community as a means of measuring the company’s ability to fund its capital program.  It is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry.

 

Capital Expenditures

 

The following table sets forth certain historical information regarding capitalized expenditures for our oil and gas acquisition, exploration, and development activities and property sales (in thousands):

 

 

 

For the Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Acquisitions:

 

 

 

 

 

Proved

 

$

51

 

$

 

Unproved

 

1,922

 

441

 

 

 

1,973

 

441

 

Exploration and development:

 

 

 

 

 

Land and seismic

 

37,212

 

32,426

 

Exploration and development

 

362,499

 

304,575

 

 

 

399,711

 

337,001

 

Sales proceeds:

 

 

 

 

 

Proved

 

(171

)

(11,354

)

Unproved

 

(942

)

(494

)

 

 

(1,113

)

(11,848

)

 

 

$

400,571

 

$

325,594

 

 

Capital expenditures in the table above are presented on an accrual basis.  Additions to property and equipment in the Condensed Consolidated Statements of Cash Flows reflect capital expenditures on a cash basis, when payments are made.

 

Our exploration and development expenditures increased $62.7 million (19%) from $337.0 million in the first quarter of 2011 to $399.7 million in the first of quarter 2012.  Of our total 2012 expenditures, 50% was for projects located in the Permian Basin; 45% in the Mid-Continent area; and 5% in the Gulf Coast and other.

 

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Table of Contents

 

The following table reflects wells drilled and completed by region:

 

 

 

For the Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Gross wells

 

 

 

 

 

Permian Basin

 

39

 

26

 

Mid-Continent

 

33

 

37

 

Gulf Coast / Other

 

1

 

2

 

 

 

73

 

65

 

Net wells

 

 

 

 

 

Permian Basin

 

27

 

20

 

Mid-Continent

 

12

 

13

 

Gulf Coast / Other

 

1

 

2

 

 

 

40

 

35

 

 

 

 

 

 

 

% Gross wells completed as producers

 

95%

 

97%

 

 

As of March 31, 2012 we had 24 net wells awaiting completion:  18 Mid-Continent and six Permian Basin.  We also had 24 operated rigs running; 14 in the Permian Basin and 10 in the Mid-Continent.

 

Based on current market prices and service costs, our 2012 E&D capital expenditures are presently projected to be in the range of $1.4 — 1.6 billion.  We expect nearly all of our 2012 capital to be directed towards oil or liquids-rich gas drilling in the Permian Basin and our Cana-Woodford shale play in the Mid-Continent area.  We expect our 2012 E&D capital expenditures to be funded from cash flow, long-term debt and property sales.  The timing of capital expenditures and the receipt of cash flows do not necessarily match.  Therefore, we may borrow and repay funds under our credit arrangement throughout the year.

 

As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and drilling success.  We have the flexibility to adjust our capital expenditures based upon market conditions.

 

We had no significant acquisitions or property sales in the first quarter of 2012.  In the first quarter of 2011 we sold non-core property interests for $11.8 million.  We continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our core areas of operation.

 

We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements.  These costs are considered a normal recurring cost of our ongoing operations and not an extraordinary cost of compliance.  We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact.

 

Financial Condition

 

Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and producing new reserves, the level of production from existing wells and realized commodity prices.  To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, bank borrowings, and access to capital markets.  We anticipate periodically accessing our credit facility to finance our working capital needs and growth.

 

During the first quarter of 2012 our total assets increased by $307.9 million to $5.7 billion, up from $5.4 billion at December 31, 2011.  The increase was primarily due to a $293.7 million increase in our net oil and gas properties.

 

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At March 31, 2012, our total liabilities increased to $2.5 billion, up $208.0 million from $2.3 billion at December 31, 2011.  The increase is primarily made up of an increase in long-term debt of $167.0 million and an increase of $66.3 million in noncurrent deferred income taxes, offset by a $28.6 million decrease in net current liabilities.  The decrease in net current liabilities was a result of net decreases in operations related accounts payable and accrued liabilities.

 

Stockholders’ equity rose $99.8 million to $3.2 billion at the end of the first quarter of 2012 compared to $3.1 billion at December 31, 2011.  The increase is mainly due to our net income of $106.1 million, which was partially offset by dividends of $10.3 million.

 

Dividends

 

On February 22, 2012 the Board of Directors increased our regular cash dividend on our common stock from $0.10 to $0.12 per common share.  Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

 

Working Capital Analysis

 

Our working capital balance fluctuates primarily as a result of our exploration and development activities, our realized commodity prices and our production operating activities.  Working capital is also impacted by our current tax provisions, accrued G&A and changes in the fair value of our outstanding derivative instruments.

 

In the first quarter of 2012 our working capital increased $35.8 million from a deficit of $158.4 million at year-end 2011 to a deficit of $122.6 million at March 31, 2012.

 

Working capital increased primarily because of the following:

 

                Our operations related accounts payable and accrued liabilities decreased by $33.2 million

 

                Our operations related accounts receivable increased by $2.9 million.

 

                Cash and cash equivalents increased by $2 million.

 

These working capital increases were partially offset by the following:

 

                The net fair value of our derivative instruments liability increased by $4.1 million.

 

Our receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries.  Our collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables have not been significant.

 

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Long-Term Debt

 

Debt at March 31, 2012 and December 31, 2011 consisted of the following (in thousands):

 

 

 

March 31,
2012

 

December 31,
2011

 

Bank debt

 

$

222,000

 

$

55,000

 

7.125% Senior Notes due 2017

 

350,000

 

350,000

 

Total long-term debt

 

$

572,000

 

$

405,000

 

 

In April, 2012 we issued $750 million of 5.875% senior notes due 2022, with interest payable semiannually in May and November.  The notes were sold to the public at par.  We may redeem the notes in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and thereafter.