06.30.2013 Form 10-Q
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TABLE OF CONTENTS


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
T
 
Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2013
o
 
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from            to          

Commission file number 1-9735
BERRY PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE
(State of incorporation or organization)
 
77-0079387
(I.R.S. Employer Identification Number)
1999 Broadway, Suite 3700
Denver, Colorado 80202
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (303) 999-4400
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 T    NO £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES T    NO £
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer T
 
Accelerated filer £
 
Non-accelerated filer £
 (Do not check if a
smaller reporting company)
 
Smaller reporting company £
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES £    NO T
As of August 5, 2013 the registrant had 52,674,211 shares of Class A Common Stock ($0.01 par value) outstanding. The registrant also had 1,763,866 shares of Class B Stock ($0.01 par value) outstanding on August 5, 2013, all of which is held by a single holder.


Table of Contents


BERRY PETROLEUM COMPANY
INDEX TO FORM 10-Q
June 30, 2013

 
Page
 

2

Table of Contents

PART I. FINANCIAL INFORMATION

BERRY PETROLEUM COMPANY
Condensed Balance Sheets
(Unaudited)
(In Thousands, Except Share Information)

 
June 30, 2013
 
December 31, 2012
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
8,914

 
$
312

Restricted short-term investments
125

 
125

Accounts receivable
138,649

 
122,159

Deferred income taxes
185

 
703

Derivative instruments
18,377

 
14,661

Prepaid expenses and other
19,005

 
19,065

Total current assets
185,255

 
157,025

Oil and natural gas properties (successful efforts basis), buildings and equipment, net
3,240,447

 
3,128,502

Derivative instruments
34,867

 
10,891

Other assets
25,933

 
28,984

 
$
3,486,502

 
$
3,325,402

LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
105,912

 
$
175,893

Revenue and royalties payable
42,618

 
57,021

Accrued liabilities
46,166

 
51,151

Derivative instruments

 
1,111

Deferred income taxes
6,598

 
1,456

10.25% Senior notes due 2014, net of unamortized discount of $1,553
203,704

 

Total current liabilities
404,998

 
286,632

Long-term liabilities:
 
 
 
Deferred income taxes
311,449

 
255,471

Senior secured revolving credit facility
646,000

 
562,900

10.25% Senior notes due 2014, net of unamortized discount of $2,340

 
202,917

6.75% Senior notes due 2020
300,000

 
300,000

6.375% Senior notes due 2022
600,000

 
600,000

Asset retirement obligations
94,424

 
82,316

Derivative instruments

 
1,239

Other long-term liabilities
23,127

 
19,136

 
1,975,000

 
2,023,979

Shareholders' equity:
 
 
 
Preferred stock, $0.01 par value, 2,000,000 shares authorized; no shares outstanding

 

Capital stock, $0.01 par value:
 
 
 
Class A Common Stock, 100,000,000 shares authorized; 52,672,162 and 52,428,423 shares issued and outstanding, respectively
527

 
524

Class B Stock, 3,000,000 shares authorized; 1,763,866 shares issued and outstanding (liquidation preference of $0.50 per share)
18

 
18

Capital in excess of par value
371,425

 
364,710

Retained earnings
734,534

 
649,539

Total shareholders' equity
1,106,504

 
1,014,791

 
$
3,486,502

 
$
3,325,402

The accompanying notes are an integral part of these Condensed Financial Statements.

3

Table of Contents

BERRY PETROLEUM COMPANY
Condensed Statements of Operations
(Unaudited)
(In Thousands, Except Per Share Data)

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
REVENUES
 
 
 
 
 
 
 
Oil and natural gas sales
$
274,715

 
$
221,781

 
$
541,487

 
$
455,434

Electricity sales
9,513

 
5,860

 
17,102

 
11,840

Natural gas marketing
2,255

 
1,580

 
4,282

 
3,439

(Loss) gain on sale of assets

 
(163
)
 
23

 
1,600

Interest and other income, net
374

 
645

 
849

 
1,392

 
286,857

 
229,703

 
563,743

 
473,705

EXPENSES
 
 
 
 
 
 
 
Operating costs—oil and natural gas production
91,277

 
62,426

 
177,425

 
116,647

Operating costs—electricity generation
6,337

 
4,256

 
11,633

 
9,273

Production taxes
11,004

 
9,690

 
21,788

 
20,348

Depreciation, depletion & amortization—oil and natural gas production
69,839

 
52,026

 
137,923

 
99,982

Depreciation, depletion & amortization—electricity generation
433

 
455

 
827

 
921

Natural gas marketing
2,198

 
1,387

 
4,076

 
3,164

General and administrative
19,430

 
17,965

 
41,708

 
35,706

Interest
24,879

 
20,789

 
49,566

 
40,893

Dry hole, abandonment, impairment and exploration
872

 
1,582

 
1,834

 
4,621

Impairment of oil and natural gas properties

 
38

 
2,467

 
66

Extinguishment of debt

 
41,526

 

 
41,526

Realized and unrealized gain on derivatives, net
(35,622
)
 
(113,082
)
 
(34,885
)
 
(84,601
)
 
190,647

 
99,058

 
414,362

 
288,546

Earnings before income taxes
96,210

 
130,645

 
149,381

 
185,159

Income tax provision
34,846

 
49,629

 
55,583

 
70,245

Net earnings
$
61,364

 
$
81,016

 
$
93,798

 
$
114,914

Basic net earnings per share
$
1.11

 
$
1.47

 
$
1.69

 
$
2.08

Diluted net earnings per share
$
1.10

 
$
1.46

 
$
1.68

 
$
2.07

Dividends per share
$
0.08

 
$
0.08

 
$
0.16

 
$
0.16

The accompanying notes are an integral part of these Condensed Financial Statements.

4

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BERRY PETROLEUM COMPANY
Condensed Statements of Comprehensive Earnings
(Unaudited)
(In Thousands)
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
Net earnings
$
61,364

 
$
81,016

 
$
93,798

 
$
114,914

Other comprehensive earnings, net of income taxes:
 
 
 
 
 
 
 
Amortization of accumulated other comprehensive loss (AOCL) related to de-designated hedges, net of income tax benefits of $0, $618, $0 and $1,394, respectively

 
1,009

 

 
2,276

Other comprehensive earnings
$

 
$
1,009

 
$

 
$
2,276

Comprehensive earnings
$
61,364

 
$
82,025

 
$
93,798

 
$
117,190

The accompanying notes are an integral part of these Condensed Financial Statements.


5

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BERRY PETROLEUM COMPANY
Condensed Statements of Cash Flows
(Unaudited)
(In Thousands)
 
Six Months Ended
 
June 30,
 
2013
 
2012
Cash flows from operating activities:
 
 
 
Net earnings
$
93,798

 
$
114,914

Depreciation, depletion and amortization
138,749

 
100,903

Gain on sale of assets
(23
)
 
(1,600
)
Extinguishment of debt

 
6,842

Amortization of debt issuance costs and net discount
3,438

 
3,688

Impairment of oil and natural gas properties
2,467

 
66

Dry hole and impairment
713

 
211

Derivatives
(30,041
)
 
(66,901
)
Stock-based compensation expense
5,903

 
5,426

Deferred income taxes
61,639

 
66,782

Other, net
2,226

 
(524
)
Allowance for bad debt

 
315

Change in book overdraft
(14,885
)
 
(2,628
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(16,518
)
 
9,063

Inventories, prepaid expenses, and other current assets
242

 
(4,702
)
Accounts payable and revenue and royalties payable
(10,741
)
 
7,755

Accrued interest and other accrued liabilities
(5,007
)
 
8,457

Net cash provided by operating activities
231,960


248,067

Cash flows from investing activities:
 
 
 
Development and exploration of oil and natural gas properties
(303,228
)
 
(328,968
)
Property acquisitions
(3,080
)
 
(24,851
)
Capitalized interest
(3,450
)
 
(9,723
)
Proceeds from sale of assets
11,511

 
15,722

Deposits on asset sales

 
(3,300
)
Net cash used in investing activities
(298,247
)

(351,120
)
Cash flows from financing activities:
 
 
 
Proceeds from issuance of 6.375% Senior notes due 2022

 
600,000

Repurchase of 8.25% Senior subordinated notes due 2016

 
(200,000
)
Repurchase of 10.25% Senior notes due 2014

 
(149,999
)
Long-term borrowings under credit facility
490,700

 
858,700

Repayments of long-term borrowings under credit facility
(407,600
)
 
(989,700
)
Financing obligation
(223
)
 
(202
)
Debt issuance costs

 
(11,424
)
Dividends paid
(8,803
)
 
(8,771
)
Stock options and restricted stock issued
65

 
3,497

Excess income tax benefit
750

 
735

Net cash provided by financing activities
74,889


102,836

Net increase (decrease) in cash and cash equivalents
8,602

 
(217
)
Cash and cash equivalents at beginning of period
312

 
298

Cash and cash equivalents at end of period
$
8,914

 
$
81

Noncash investing activities:
 
 
 
Accrued capital expenditures
$
40,607

 
$
55,311

Asset retirement obligations
10,607

 
15,012

The accompanying notes are an integral part of these Condensed Financial Statements.

6

Table of Contents

BERRY PETROLEUM COMPANY
Condensed Statements of Shareholders' Equity
(Unaudited)
(In Thousands, Except Per Share Data)

 
Class
A
 
Class
B
 
Capital in
Excess of Par
Value
 
Retained
Earnings
 
Total
Shareholders'
Equity
Balances at December 31, 2012
$
524

 
$
18

 
$
364,710

 
$
649,539

 
$
1,014,791

Stock options and restricted stock issued
3

 

 
62

 

 
65

Stock based compensation expense

 

 
5,903

 

 
5,903

Income tax effect of stock option exercises

 

 
750

 

 
750

Dividends ($0.16 per share)

 

 

 
(8,803
)
 
(8,803
)
Net earnings

 

 

 
93,798

 
93,798

Balances at June 30, 2013
$
527

 
$
18

 
$
371,425

 
$
734,534

 
$
1,106,504

The accompanying notes are an integral part of these Condensed Financial Statements.

7

Table of Contents

BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements
(Unaudited)

1. Basis of Presentation

These Condensed Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial reporting. Pursuant to the rules and regulations of the Securities and Exchange Commission (SEC), the unaudited Condensed Financial Statements do not include all disclosures required by GAAP. For a more complete understanding of Berry Petroleum Company's (the Company) operations, financial position and accounting policies, the unaudited Condensed Financial Statements and notes thereto should be read in conjunction with the Company's Annual Report on Form 10-K for the year ended December 31, 2012, previously filed with the SEC.

All adjustments, consisting of normal and recurring accruals, which are, in the opinion of management, necessary to fairly state the Company's Condensed Financial Statements have been included herein. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in prices received for oil and natural gas, as well as other factors. In the course of preparing the Condensed Financial Statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and to prepare disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events, and, accordingly, actual results could differ from amounts previously established.
 
The Company's cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at December 31, 2012 was $14.9 million, representing outstanding checks in excess of the bank balance (book overdraft). There were no outstanding checks in excess of the bank balance at June 30, 2013.

Recent Accounting Standards

There are no material new accounting pronouncements that have been issued but not yet adopted by the Company as of June 30, 2013.

2. Acquisitions and Divestitures

2012 Acquisitions

On September 12, 2012, the Company completed the acquisition of approximately 14,000 net acres contiguous to the Company's Brundage Canyon asset in the Uinta for an aggregate purchase price of $39.6 million, including usual and customary post-closing adjustments. Disclosures of purchase price allocation and also of pro forma revenues and net earnings for this acquisition are not material and have not been presented.

On April 13, 2012, the Company completed the acquisition of approximately 2,000 net acres and one well in the Wolfberry trend in the Permian for an aggregate purchase price of $14.9 million including usual and customary post-closing adjustments. Disclosures of purchase price allocation and also of pro forma revenues and net earnings for this acquisition are not material and have not been presented.

2012 Divestiture

On December 21, 2011, the Company entered into an agreement to sell its assets related to proved developed properties in Elko, Eureka and Nye Counties, Nevada, which closed on January 31, 2012, for total cash consideration of $15.6 million. The Company recorded a $1.6 million gain in conjunction with the sale. The gain was recorded in the Condensed Statements of Operations under the caption (loss) gain on sale of assets.


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Table of Contents
BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)

3. Debt

Senior Secured Revolving Credit Facility

As of June 30, 2013, the Company's credit facility, which matures on May 13, 2016, had a borrowing base of $1.4 billion, subject to lender commitments. At June 30, 2013, lender commitments under the facility were $1.2 billion. Borrowings under the credit facility bear interest at either (i) LIBOR plus a margin between 1.50% and 2.50% or (ii) the prime rate plus a margin between 0.50% and 1.50%, in each case, based on the amount utilized. The annual commitment fee on the unused portion of the credit facility ranges between 0.35% and 0.50% based on the amount utilized.

As of June 30, 2013, there were $646.0 million in outstanding borrowings under the credit facility and $23.2 million in outstanding letters of credit, leaving $530.8 million in borrowing capacity available under the credit facility. The maximum amount available under the credit facility is subject to semi-annual redeterminations of the borrowing base in April and October of each year, based on the value of the Company's proved oil and natural gas reserves, in accordance with the lenders' customary procedures and practices. The Company and the lenders each have the right to one additional redetermination each year. The semi-annual redetermination in April 2013 did not result in any changes to the borrowing base, lender commitments, or other terms of the credit facility.

Maturity of 2014 Notes

The Company's 10.25% senior notes due 2014 (2014 Notes) are scheduled to mature on June 1, 2014. As a result, all $205.3 million aggregate principal amount of the 2014 Notes is classified as a current obligation on the Company's Condensed Balance Sheet as of June 30, 2013. The Company's ability to repay or refinance the aggregate principal amount of the 2014 Notes is subject to restrictions contained in the Merger Agreement. See Note 11 to the Condensed Financial Statements. While the Company has not yet determined how it will repay or refinance the 2014 Notes, the Company may do so through multiple methods which it may pursue separately or in combination, including (i) issuing new debt or equity securities and (ii) borrowing under the Company's credit facility, which may require seeking additional availability under the credit facility. If the Company is unable to complete a refinancing, it would be in default under the indenture governing the 2014 Notes, which would also cause the Company to be in default under its credit facility and the indentures governing its other senior notes, and would result in indebtedness outstanding under those agreements to be declared immediately due and payable. In addition, failure to comply with any of the indentures or covenants under the senior notes and credit facility could adversely affect the Company's ability to fund ongoing operations and future capital expenditures, as well as the ability to pay distributions to shareholders.

4. Income Taxes

The effective income tax rate for the three months ended June 30, 2013 and 2012 was 36.2% and 38.0%, respectively. The effective income tax rate for the six months ended June 30, 2013 and 2012 was 37.2% and 37.9%, respectively. The Company's provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes, domestic production activities deduction, percentage depletion, nondeductible employee compensation and other permanent differences. The decrease in the effective income tax rate for the three months ended June 30, 2013 was primarily due to a reduction in uncertain income tax positions recognized for closing statutes.
 

As of June 30, 2013, the Company had a gross liability for uncertain income tax benefits of $20.1 million, $15.0 million of which, if recognized, would impact the effective income tax rate. During the second quarter of 2013, the Company recognized a benefit of $1.9 million related to closing statutes. Consistent with the Company's policy, interest and penalties on income taxes have been recorded as a component of the income tax provision. The Company estimates that it is reasonably possible that the balance of unrecognized income tax benefits as of June 30, 2013 could decrease by a maximum of $4.8 million in the next 12 months due to the expiration of statutes of limitation and audit settlements.

5. Earnings Per Share

Basic net earnings per share is calculated by dividing net earnings available to common shareholders by the weighted average shares outstanding-basic during each period. Diluted earnings per share is calculated by dividing earnings available to common shareholders by the weighted average shares outstanding-dilutive, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and outstanding stock options. No potential shares of common stock are included in the computation of any diluted per share amount when a net loss exists.

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Table of Contents
BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)
5. Earnings Per Share (Continued)


The two-class method of computing net earnings per share is required for those entities that have participating securities. The two-class method is an earnings allocation formula that determines net earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Unvested restricted shares issued under the Company's equity incentive plans prior to January 1, 2010 have the right to receive non-forfeitable dividends, participating on an equal basis with common shares, and thus are classified as participating securities. Participating securities do not have a contractual obligation to share in the Company's losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Unvested restricted shares issued subsequent to January 1, 2010 under the Company's equity incentive plans do not participate in dividends. Stock options issued under the Company's equity incentive plans do not participate in dividends.

The following table shows the computation of basic and diluted net earnings per share for the three and six months ended June 30, 2013 and 2012:

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
(in thousands, except per share data)
2013
 
2012
 
2013
 
2012
Net earnings
$
61,364

 
$
81,016

 
$
93,798

 
$
114,914

Less: net earnings allocable to participating securities
112

 
399

 
194

 
556

Net earnings available for common shareholders
$
61,252

 
$
80,617

 
$
93,604

 
$
114,358

 
 
 
 
 
 
 
 
Basic net earnings per share
$
1.11

 
$
1.47

 
$
1.69

 
$
2.08

Diluted net earnings per share
$
1.10

 
$
1.46

 
$
1.68

 
$
2.07

 
 
 
 
 
 
 
 
Basic weighted average shares outstanding
55,302

 
54,942

 
55,245

 
54,851

Add: Dilutive effects of stock options and RSUs
417

 
352

 
406

 
451

Dilutive weighted average shares outstanding
55,719

 
55,294

 
55,651

 
55,302

 
Not included in the diluted earnings per share calculation were 0.3 million and 0.7 million stock options and RSUs, for the three and six months ended June 30, 2013, respectively, because their effect would have been anti-dilutive. Not included in the diluted earnings per share calculation were 0.7 million and 0.3 million stock options and RSUs, for the three and six months ended June 30, 2012, respectively, because their effect would have been anti-dilutive.


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Table of Contents
BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)


6. Asset Retirement Obligations

The following table summarizes the activity for the Company's asset retirement obligations (AROs) for the six months ended June 30, 2013 and 2012:

 
Six Months Ended
 
June 30,
(in thousands)
2013
 
2012
Beginning balance at January 1
$
86,746

 
$
64,019

Liabilities incurred
4,700

 
4,024

Liabilities settled
(2,007
)
 
(1,668
)
Liabilities assumed

 
1,626

Disposition of assets
(40
)
 
(705
)
Accretion expense
3,548

 
2,596

Revisions in estimated cash flows
5,907

 
10,988

Ending balance at June 30
$
98,854

 
$
80,880


ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and natural gas properties. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance.

7. Equity Incentive Compensation Plans

Stock-based compensation is measured at the grant date based on the fair value of the awards. The fair value is recognized on a straight-line basis over the requisite service period (generally the vesting period).

Total compensation cost recognized in the Condensed Statements of Operations for the grants under the Company's equity incentive compensation plans was $2.6 million and $2.2 million during the three months ended June 30, 2013 and 2012, respectively, and $5.6 million and $5.2 million during the six months ended June 30, 2013 and 2012, respectively.


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BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)

Stock Options

The following table summarizes stock option activity for the six months ended June 30, 2013:

 
Number of
Shares
 
Weighted
Average
Exercise
Price
 
Aggregate
Intrinsic Value
(in thousands)(1)
 
Weighted Average
Remaining Contractual
Term (Years)
Outstanding at January 1, 2013
1,387,592

 
$
33.71

 
$
4,681

 
 
Granted

 

 


 
 
Exercised
(3,000
)
 
21.58

 
76

 
 
Canceled/expired

 

 


 
 
Outstanding at June 30, 2013
1,384,592

 
$
33.74

 
$
13,465

 
3.59
Vested and expected to vest at June 30, 2013
1,383,778

 
$
33.73

 
$
13,465

 
3.59
Exercisable at June 30, 2013
1,278,372

 
$
32.29

 
$
13,465

 
3.20
__________________________________
(1)
The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option.
 
As of June 30, 2013, there were $2.0 million of total unrecognized compensation costs related to outstanding stock options. These costs are expected to be recognized over 2.8 years.

Restricted Stock Units

The following table summarizes restricted stock unit (RSU) activity for the six months ended June 30, 2013:

 
RSUs
 
Weighted
Average
Grant Date
Fair Value
 
Vest Date Fair
Value
(in thousands)
Outstanding at January 1, 2013
981,877

 
$
26.72

 
 

Granted
264,033

 
45.27

 
 

Issued
(176,724
)
 
24.68

 
$
6,884

Canceled/expired
(13,707
)
 
43.85

 
 

Outstanding at June 30, 2013(1)(2)
1,055,479

 
$
32.02

 
 

__________________________________
(1)
The balance outstanding includes 58,036 RSUs granted to non-employee directors that are 100% vested at date of grant, but are subject to deferral elections delaying the date on which the corresponding shares are issued.
(2)
The balance outstanding includes 510,967 RSUs granted to executive officers and other officers that have vested in accordance with the RSU agreement but are subject to deferral elections delaying the date on which the corresponding shares are issued.

As of June 30, 2013, there were $18.9 million of total unrecognized compensation costs related to RSUs granted. These costs are expected to be recognized over 3.8 years.


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BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)
7. Equity Incentive Compensation Plans (Continued)


Performance Share Program

The following table summarizes performance share award activity for the six months ended June 30, 2013:

 
Performance
Share Awards(1)
 
Weighted
Average
Grant Date
Fair Value
 
Vest Date Fair
Value
(in thousands)
Outstanding at January 1, 2013
222,587

 
$
45.79

 
 

Granted

 

 
 

Issued
(64,922
)
 
32.75

 
$
2,990

Canceled/expired
(34,742
)
 
28.32

 
 

Outstanding at June 30, 2013
122,923

 
$
57.61

 
 

__________________________________
(1)
For outstanding shares, reflects the maximum number of performance shares that can be issued.

As of June 30, 2013, there were $1.5 million of total unrecognized compensation costs related to performance shares granted. These costs are expected to be recognized over 1.5 years.

8. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable, economic cash flow from its oil production by reducing its exposure to price fluctuations. The Company has historically entered into financial commodity swap and collar contracts to fix the floor and ceiling prices received for a portion of the Company's oil and natural gas production. During the second quarter of 2012, the Company began entering into derivative contracts to fix the floor and ceiling prices paid for a portion of its natural gas consumption. The terms of the Company's derivative contracts depend on various factors, including management's view of future crude oil and natural gas prices, acquisition economics on purchased assets, future financial commitments, and other considerations. The Company periodically enters into interest rate derivative agreements to protect against changes in interest rates on its floating rate debt. The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings. For further discussion related to the fair value of the Company's derivatives, see Note 9 to the Condensed Financial Statements.

As of June 30, 2013, the Company had commodity derivatives associated with the following volumes:

 
2013
 
2014
 
2015
Oil sales, Bbl/D
19,800

 
21,000

 
3,000

Natural gas purchases, MMBtu/D
10,000

 

 


The Company entered into the following derivative instruments during the six months ended June 30, 2013:

Crude Oil Sales Three-Way Collars
Term
 
Index
 
Average Barrels
Per Day
 
Sold Put / Purchased Put / Sold Call
Full year 2013 and 2014
 
ICE Brent
 
1,000
 
$80.00 / $100.00 / $114.05
Full year 2014
 
NYMEX WTI
 
1,000
 
$70.00 / $90.00 / $102.00
Crude Oil Sales (NYMEX WTI) Swaps
Term
 
Average Barrels
Per Day
 
Weighted Average Price
Full year 2014
 
11,500
 
$90.14

13

Table of Contents
BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)
8. Derivative Instruments (Continued)



Crude Oil Sales (NYMEX WTI to ICE Brent) Basis Swaps
Term
 
Average Barrels
Per Day
 
Weighted Average Price
Full year 2014
 
10,000
 
$11.60
Full year 2015
 
8,000
 
$11.60

Crude Oil Sales (NYMEX WTI to Midland) Basis Swaps
Term
 
Average Barrels
Per Day
 
Weighted Average Price
April 2013 - December 2013
 
4,000
 
$1.48


In March 2012, the Company terminated certain of its natural gas derivative instruments, which were associated with a total of 15,000 MMBtu/D for the remainder of 2012. The termination resulted in a net loss of $1.9 million, including cash settlements and non-cash fair value losses, and was recorded in the Condensed Statements of Operations under the caption realized and unrealized gain on derivatives, net.

The Company routinely enters into derivative contracts with a variety of counterparties, typically resulting in individual derivative instruments with both fair value asset and liability positions. The Company nets the fair values of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which mitigate the credit risk of the Company's derivative instruments by providing for net settlement over the term of the contract and in the event of default or termination of the contract. The tables below summarize the fair value of derivative assets and liabilities and the effect of netting on the Condensed Balance Sheets:
(in millions)
 
 
June 30, 2013
Description
Balance Sheet Classification
 
Gross Amounts of Recognized Assets or Liabilities
 
Gross Amounts Offset in the Condensed Balance Sheets
 
Net Amounts of Assets or Liabilities Presented in the Condensed Balance Sheets
Assets
 
 
 
 
 
 
 
Commodity derivative instruments
Current
 
$
23.8

 
$
(5.5
)
 
$
18.3

Commodity derivative instruments
Long-term
 
35.0

 
(0.1
)
 
34.9

Total assets
 
 
$
58.8

 
$
(5.6
)
 
$
53.2

 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
Commodity derivative instruments
Current
 
$
5.4

 
$
(5.4
)
 
$

Commodity derivative instruments
Long-term
 
0.2

 
(0.2
)
 

Total liabilities
 
 
$
5.6

 
$
(5.6
)
 
$



14

Table of Contents
BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)
8. Derivative Instruments (Continued)


(in millions)
 
 
December 31, 2012
Description
Balance Sheet Classification
 
Gross Amounts of Recognized Assets or Liabilities
 
Gross Amounts Offset in the Condensed Balance Sheets
 
Net Amounts of Assets or Liabilities Presented in the Condensed Balance Sheets
Assets
 
 
 
 
 
 
 
Commodity derivative instruments
Current
 
$
16.4

 
$
(1.7
)
 
$
14.7

Commodity derivative instruments
Long-term
 
10.9

 

 
10.9

Total assets
 
 
$
27.3

 
$
(1.7
)
 
$
25.6

 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
Commodity derivative instruments
Current
 
$
2.8

 
$
(1.7
)
 
$
1.1

Commodity derivative instruments
Long-term
 
1.2

 

 
1.2

Total liabilities
 
 
$
4.0

 
$
(1.7
)
 
$
2.3


The table below summarizes the location and the amount of derivative instrument losses (gains) before income taxes reported in the Condensed Statements of Operations for the periods indicated:

 
 
 
Three Months Ended
 
Six Months Ended
(in millions)
Location of Loss (Gain)
Recognized in Earnings
 
June 30,
June 30,
Description of Loss (Gain)
2013
 
2012
 
2013
 
2012
Commodity
 
 
 
 
 
 
 
 
 
Loss reclassified from AOCL into earnings (amortization of frozen amounts)
Oil and natural gas sales
 
$

 
$
2.5

 
$

 
$
5.2

Gain recognized in earnings (cash settlements and mark-to-market movements)
Realized and unrealized gain on derivatives, net
 
(35.6
)
 
(113.1
)
 
(34.9
)
 
(84.6
)
Interest rate
 
 
 
 
 
 
 
 
 
Gain reclassified from AOCL into earnings (amortization of frozen amounts)
Interest
 
$

 
$
(0.9
)
 
$

 
$
(1.5
)

Credit Risk

The Company does not require collateral or other security from counterparties to support derivative instruments. However, the agreements with those counterparties typically contain netting provisions such that if a default occurs, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contract with the amount due from the defaulting party. As a result of the netting provisions, the Company's maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that the Company would have incurred if all counterparties to its derivative contracts failed to perform at June 30, 2013 was $53.2 million.

As of June 30, 2013, the counterparties to the Company's commodity derivative contracts consist of nine financial institutions. The Company's counterparties or their affiliates are also lenders under the Company's credit facility. As a result, the counterparties to the Company's derivative agreements share in the collateral supporting the Company's credit facility. The Company is not generally required to post additional collateral under derivative agreements.

Certain of the Company's derivative agreements contain cross default provisions that require acceleration of amounts due under such agreements if the Company were to default on its obligations under its material debt agreements. In addition, if the Company were to default on certain of its material debt agreements, including its derivative agreements, the Company would be

15

Table of Contents
BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)
8. Derivative Instruments (Continued)


in default under the credit facility. As of June 30, 2013, the Company was not in a net liability position with any of the counterparties to the Company's derivative instruments. As of June 30, 2013, the Company's largest three counterparties accounted for 52% of the value of its total net derivative positions.

9. Fair Value Measurements

The authoritative guidance for fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

A financial instrument's categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. The Company recognizes transfers between levels at the end of the reporting period for which the transfer has occurred.

The fair value of all derivative instruments is estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value of all derivative instruments is estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services, and the Company has made no adjustments to the obtained prices. The independent pricing services publish observable market information from multiple brokers and exchanges. All valuations were compared against counterparty valuations to verify the reasonableness of prices. The Company also considers counterparty credit risk and its own credit risk in its determination of all estimated fair values. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds.

Assets (Liabilities) Measured at Fair Value on a Recurring Basis

The following table presents information about the Company's financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and December 31, 2012, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values:

(in millions)
Total
 
Level 1
 
Level 2
 
Level 3
Commodity derivative asset, net
 
 
 
 
 
 
 
June 30, 2013
$
53.2

 
$

 
$
53.2

 
$

December 31, 2012
$
23.2

 
$

 
$
23.2

 
$



16

Table of Contents
BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)
9. Fair Value Measurements (Continued)


Fair Market Value of Financial Instruments

The Company uses various assumptions and methods in estimating the fair values of its financial instruments. The following table presents fair value information about the Company's financial instruments:
June 30, 2013
Carrying
Amount
 
Estimated
Fair Value
(in millions)
 
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash and cash equivalents
$
9

 
$
9

 
$

 
$

 
$
9

Senior secured revolving credit facility(1)
646

 

 
646

 

 
646

10.25% Senior notes due 2014(2)
205

 
221

 

 

 
221

6.75% Senior notes due 2020
300

 
311

 

 

 
311

6.375% Senior notes due 2022
600

 
599

 

 

 
599

 
$
1,760

 
$
1,140

 
$
646

 
$

 
$
1,786

__________________________________
(1)
The Company's credit facility can be repaid at any time without penalty. Interest is generally fixed for 30-day increments at the prime rate or LIBOR plus a stipulated margin for the amount utilized and at a stipulated percentage as a commitment fee for the portion not utilized. The carrying amount of the credit facility approximated fair value due to the short-term maturities of the borrowings and because the borrowings bear interest at variable market rates.
(2)
Carrying amount does not include unamortized discount of $1.6 million.

December 31, 2012
Carrying
Amount
 
Estimated
Fair Value
(in millions)
 
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash and cash equivalents
$

 
$

 
$

 
$

 
$

Senior secured revolving credit facility(1)
563

 

 
563

 

 
563

10.25% Senior notes due 2014(2)
205

 
229

 

 

 
229

6.75% Senior notes due 2020
300

 
323

 

 

 
323

6.375% Senior notes due 2022
600

 
627

 

 

 
627

 
$
1,668

 
$
1,179

 
$
563

 
$

 
$
1,742

_________________________________
(1)
The Company's credit facility can be repaid at any time without penalty. Interest is generally fixed for 30-day increments at the prime rate or LIBOR plus a stipulated margin for the amount utilized and at a stipulated percentage as a commitment fee for the portion not utilized. The carrying amount of the credit facility approximated fair value due to the short-term maturities of the borrowings and because the borrowings bear interest at variable market rates.
(2)
Carrying amount does not include unamortized discount of $2.3 million.

10. Commitments and Contingencies

E. Texas Gathering System

In July 2009, the Company closed on the financing of its E. Texas natural gas gathering system for $18.4 million in cash. The Company entered into concurrent long-term natural gas gathering agreements for the E. Texas production which contained an embedded lease. Accordingly, the $16.7 million net book value of the property is being depreciated over the remaining useful life of the asset and the cash received of $18.4 million was recorded as a financing obligation. A portion of the payments under the agreements is recorded as gathering expense and is presented in the Condensed Financial Statements under the caption operating costs—oil and natural gas production. In addition, a portion of the payments is recorded as interest expense, and the balance of the payments is recorded as a reduction to the financing obligation. There are no minimum payments required under these agreements. For the three months ended June 30, 2013 and 2012, the Company incurred net costs of $0.5 million and $0.6 million, respectively, under the agreements. For the six months ended June 30, 2013 and 2012, the Company incurred net costs of $1.0 million and $1.4 million, respectively, under the agreements.


17

BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)

Carry and Earning Agreement

On January 14, 2011, the Company entered into an amendment relating to certain contractual obligations to a third-party co-owner of certain Piceance assets in Colorado. The amendment waives the $0.2 million penalty for each well not spud by February 2011 and requires the Company to reassign to such co-owner, by January 31, 2020, all of the interest acquired by the Company from the co-owner in each 160-acre tract in which the Company has not drilled and completed a well that is producing or capable of producing from a designated formation, or deeper formation, on January 1, 2020. The amendment also requires the Company to pay the first $9.0 million of costs incurred in connection with the construction of either an extension of the existing access road or a new access road, including the third party's 50% share. Pursuant to the terms of the amendment, if by June 30, 2013, the Company did not expend $9.0 million on the construction of either the extension of the road or a new road, then the Company was obligated to pay the third party 50% of the difference between $12.0 million and the actual amount expended on road construction as of such date. The Company agreed in principal with the third party to extend such deadline until September 30, 2013. Such deadline is subject to further extension to no later than December 31, 2014 under the terms of the amendment. Due to the need to obtain regulatory approvals, the Company has not yet commenced construction of either an extension of the existing access road or a new access road and may be unable to do so by the extended deadline, thus triggering the payment obligation to the third party.

Legal Matters

Department of the Interior Notice of Proposed Debarment. On June 14, 2012, the Company received a Notice of Proposed Debarment issued by the United States Department of the Interior (DOI). Pursuant to the notice, the DOI's Office of the Inspector General is proposing to debar the Company from participation in certain federal contracts and assistance activities, including oil and natural gas leases, for a period of three years. The basis for the proposed debarment relates to the Company's purported noncompliance with Bureau of Land Management (BLM) regulations relating to the operation of certain equipment, and the submission of related site facility diagrams, in its Uinta operations. In 2011, the Company entered into a settlement agreement with the BLM and paid a $2.1 million civil penalty relating to the matter. The Company has contested the proposed debarment and believes the matter is without merit; nevertheless, in June 2013, the Company entered into an agreement with the DOI to resolve the matter administratively through an independent compliance review. The Company believes the compliance review will be completed during the third quarter of 2013.

Other. The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material effect on its financial position, results of operations or operating cash flows.

Environmental Matters

The Company has no material accrued environmental liabilities for its sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, due to some of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not result in material costs incurred.

11. LinnCo, LLC Merger

On February 20, 2013, the Company, Linn Energy, LLC (Linn), LinnCo, LLC (LinnCo), Linn Acquisition Company, LLC, a direct wholly owned subsidiary of LinnCo (LinnCo Merger Sub), Bacchus HoldCo, Inc., a direct wholly owned subsidiary of the Company (HoldCo), and Bacchus Merger Sub, Inc., a direct wholly owned subsidiary of HoldCo (Bacchus Merger Sub), entered into a definitive Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which LinnCo agreed to acquire the Company in an all-stock transaction in which the Company's stockholders would receive 1.25 shares representing limited liability company interests in LinnCo (LinnCo Shares) for each share of the Company's common stock.


18


BERRY PETROLEUM COMPANY
Notes to Condensed Financial Statements (Continued)
(Unaudited)
11. LinnCO, LLC Merger (Continued)

The transaction will occur through multiple steps. First, the Company will engage in a holding company merger (the HoldCo Merger) involving HoldCo and Bacchus Merger Sub. In the HoldCo Merger, Bacchus Merger Sub will merge with and into the Company, with the Company surviving as a wholly owned subsidiary of HoldCo, and each issued and outstanding share of the Company's Class A common stock and Class B common stock will convert into the right to receive one equivalent share of Class A common stock and one equivalent share of Class B common stock, respectively, of HoldCo.

Second, promptly after the HoldCo Merger, the Company will be converted into a limited liability company. Third, promptly following such conversion, HoldCo will be merged with and into LinnCo Merger Sub, with LinnCo Merger Sub surviving as the surviving company (the LinnCo Merger). In the LinnCo Merger, each share of Holdco's Class A common stock and each share of Holdco's Class B common stock will be converted into 1.25 LinnCo Shares.

Finally, promptly following the LinnCo Merger, LinnCo will contribute all of the outstanding equity interests in LinnCo Merger Sub (and therefore also its indirect ownership interest in the Company) to Linn (the “Contribution”) in exchange for the issuance to LinnCo (the “Issuance”) of newly issued Linn common units. The number of Linn common units to be issued to LinnCo in the Issuance will be equal to the greater of (i) the aggregate number of LinnCo Shares issued in the LinnCo Merger and (ii) the number of Linn common units required to cause LinnCo to own no less than one-third of all of the outstanding Linn common units following the Contribution. In addition, for three years following the closing, Linn will pay to LinnCo additional cash distributions in the amount of $6 million per year.

The closing of the transactions is subject to customary closing conditions, including approval of the Merger Agreement and the transactions contemplated thereby by the stockholders of the Company and the holders of the shares or units of LinnCo and Linn, respectively, receipt of certain opinions by the parties with respect to the tax-free nature of the transactions, and other customary conditions.

On March 1, 2013, a purported stockholder class action captioned Nancy P. Assad Trust v. Berry Petroleum Company, et al. was filed in the United States District Court for the District of Colorado. The case was dismissed by the Court on March 20, 2013 for lack of subject matter jurisdiction, and refiled in the District Court for the City and County of Denver, Colorado on March 21, 2013, Case No. 2013CV031365. On April 5, 2013, the plaintiff filed an amended complaint alleging that the individual Company director defendants breached their fiduciary duties in connection with the proposed merger transaction with Linn and LinnCo by engaging in an unfair sales process that resulted in an unfair price for the Company, and that the entity defendants aided and abetted those breaches of fiduciary duty. The amended complaint seeks a declaration that the proposed merger transactions are unlawful and unenforceable, an order directing the individual director defendants to comply with their fiduciary duties, an injunction against consummation of the merger transactions or, in the event they are so completed, rescission of the transactions, an award of fees and costs, including attorneys' and experts' fees and expenses, and other relief.
On April 12, 2013, a second purported stockholder class action captioned David S. Hall v. Berry Petroleum Company, et al. was filed in the Court of Chancery of the State of Delaware, C.A. No. 8476-VCG. The plaintiff in this case makes allegations, and seeks relief similar to the allegations made and relief sought in the Assad case.
In response to a motion filed by the defendants, on May 20, 2013, after conferring with the Delaware judge in the Hall case, the Colorado judge stayed the Assad case, allowing the parties to proceed with one case, the Hall case, in one jurisdiction, Delaware. On July 19, 2013, the plaintiffs in the Assad case voluntarily dismissed the case without prejudice. After expedited discovery, the plaintiffs in the Hall case made a settlement proposal and the parties are currently engaged in settlement discussions. The Company believes the claims relating to the merger are without merit, and intends to defend such actions vigorously.

19

Table of Contents

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

The following is management's discussion and analysis of certain significant factors that have affected aspects of our financial position and the results of operations during the periods included in the accompanying Condensed Financial Statements. The following discussion and analysis should be read in conjunction with the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited Financial Statements for the year ended December 31, 2012, included in our Annual Report on Form 10-K and the Condensed Financial Statements included elsewhere herein.

Our revenue, profitability and future growth rate depend on many factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices have been volatile and may fluctuate widely in the future. The following charts highlight the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2010:



Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our oil and natural gas reserves. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned capital expenditures. Lower oil and natural gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil prices may result in significant non-cash fair value losses being incurred on our oil derivatives, which could cause us to experience net losses when prices rise.

Steam costs are a significant variable component of our operating costs and fluctuate based on the amount of steam we inject and the price of natural gas used to generate steam. We benefit from lower natural gas prices as a consumer of natural gas in our California operations. In the Permian, Uinta, E. Texas and Piceance, we benefit from higher natural gas pricing as a producer of natural gas. In addition, production rates, labor and equipment costs, maintenance expenses and production taxes influence our operating costs. Our results of operations may fluctuate from period to period based on such factors.

LinnCo, LLC Merger

On February 20, 2013, the Company, Linn Energy, LLC (Linn), LinnCo, LLC (LinnCo), Linn Acquisition Company, LLC, a direct wholly owned subsidiary of LinnCo (LinnCo Merger Sub), Bacchus HoldCo, Inc., a direct wholly owned subsidiary of the Company (HoldCo), and Bacchus Merger Sub, Inc., a direct wholly owned subsidiary of HoldCo (Bacchus Merger Sub), entered into a definitive Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which LinnCo agreed to acquire the Company in an all-stock transaction in which the Company's stockholders would receive 1.25 shares representing limited liability company interests in LinnCo (LinnCo Shares) for each share of the Company's common stock.

The transaction will occur through multiple steps. First, the Company will engage in a holding company merger (the HoldCo Merger) involving HoldCo and Bacchus Merger Sub. In the HoldCo Merger, Bacchus Merger Sub will merge with and

20

Table of Contents

into the Company, with the Company surviving as a wholly owned subsidiary of HoldCo, and each issued and outstanding share of the Company's Class A common stock and Class B common stock will convert into the right to receive one equivalent share of Class A common stock and one equivalent share of Class B common stock, respectively, of HoldCo.

Second, promptly after the HoldCo Merger, the Company will be converted into a limited liability company. Third, promptly following such conversion, HoldCo will be merged with and into LinnCo Merger Sub, with LinnCo Merger Sub surviving as the surviving company (the LinnCo Merger). In the LinnCo Merger, each share of Holdco's Class A common stock and each share of Holdco's Class B common stock will be converted into 1.25 LinnCo Shares.

Finally, promptly following the LinnCo Merger, LinnCo will contribute all of the outstanding equity interests in LinnCo Merger Sub (and therefore also its indirect ownership interest in the Company) to Linn (the “Contribution”) in exchange for the issuance to LinnCo (the “Issuance”) of newly issued Linn common units. The number of Linn common units to be issued to LinnCo in the Issuance will be equal to the greater of (i) the aggregate number of LinnCo Shares issued in the LinnCo Merger and (ii) the number of Linn common units required to cause LinnCo to own no less than one-third of all of the outstanding Linn common units following the Contribution. In addition, for three years following the closing, Linn will pay to LinnCo additional cash distributions in the amount of $6 million per year.

The closing of the transactions is subject to customary closing conditions, including approval of the Merger Agreement and the transactions contemplated thereby by the stockholders of the Company and the holders of the shares or units of LinnCo and Linn, respectively, receipt of certain opinions by the parties with respect to the tax-free nature of the transactions, and other customary conditions.

On March 1, 2013, a purported stockholder class action captioned Nancy P. Assad Trust v. Berry Petroleum Company, et al. was filed in the United States District Court for the District of Colorado. The case was dismissed by the Court on March 20, 2013 for lack of subject matter jurisdiction, and refiled in the District Court for the City and County of Denver, Colorado on March 21, 2013, Case No. 2013CV031365. On April 5, 2013, the plaintiff filed an amended complaint alleging that the individual Company director defendants breached their fiduciary duties in connection with the proposed merger transaction with Linn and LinnCo by engaging in an unfair sales process that resulted in an unfair price for the Company, and that the entity defendants aided and abetted those breaches of fiduciary duty. The amended complaint seeks a declaration that the proposed merger transactions are unlawful and unenforceable, an order directing the individual director defendants to comply with their fiduciary duties, an injunction against consummation of the merger transactions or, in the event they are so completed, rescission of the transactions, an award of fees and costs, including attorneys' and experts' fees and expenses, and other relief.
On April 12, 2013, a second purported stockholder class action captioned David S. Hall v. Berry Petroleum Company, et al. was filed in the Court of Chancery of the State of Delaware, C.A. No. 8476-VCG. The plaintiff in this case makes allegations, and seeks relief similar to the allegations made and relief sought in the Assad case.
In response to a motion filed by the defendants, on May 20, 2013, after conferring with the Delaware judge in the Hall case, the Colorado judge stayed the Assad case, allowing the parties to proceed with one case, the Hall case, in one jurisdiction, Delaware. On July 19, 2013, the plaintiffs in the Assad case voluntarily dismissed the case without prejudice. After expedited discovery, the plaintiffs in the Hall case made a settlement proposal and the parties are currently engaged in settlement discussions. The Company believes the claims relating to the merger are without merit, and intends to defend such actions vigorously.
Notable Second Quarter 2013 Items

Increased total production by 12% and oil production by 20% from the second quarter of 2012
Generated discretionary cash flow of $145.0 million from production of 39,529 BOE/D, of which 80% was oil(1) 
Generated an operating margin of $47.15 per BOE, supported by sales of our California heavy oil at a $5.05 average premium to WTI during the quarter(1) 
Diatomite production averaged 4,735 BOE/D, a 15% increase from the first quarter of 2013
Production from our North Midway-SunsetNew Steam Floods (NMWSSNSF) properties, which include McKittrick, averaged 2,645 BOE/D, a 12% increase from the first quarter of 2013
Drilled 26 Diatomite wells, 22 Uinta wells, 13 Permian wells and ten South Midway-SunsetSteam Floods (SMWSSSteam Floods) wells
_____________________
(1)
Discretionary cash flow and operating margin are considered non-GAAP measures and reference should be made to "Reconciliation of Non-GAAP Measures" for further explanation as well as reconciliations to the most directly comparable GAAP measures.

21

Table of Contents


Results of Operations.

In the second quarter of 2013, we reported net earnings of $61.4 million, or $1.10 per diluted share, and net cash flows from operations of $140.3 million. Net earnings in the second quarter of 2013 included a gain on derivatives of $21.2 million, net of income taxes, resulting from non-cash changes in fair values. For the first six months of 2013, we reported net earnings of $93.8 million, or $1.68 per diluted share, and net cash flows from operations of $232.0 million. Net earnings for the first six months of 2013 included a gain on derivatives of $18.9 million resulting from non-cash changes in fair values, lease write offs of $1.5 million and professional fees of $1.6 million associated with the pending LinnCo merger, in each case net of income taxes.

Operating Data.

The following table sets forth selected operating data for the three months ended:

 
June 30, 2013
 
%
 
June 30, 2012
 
%
 
March 31, 2013
 
%
Heavy oil production (BOE/D)
19,775

 
50
 
17,395

 
49
 
19,566

 
50
Light oil production (BOE/D)
11,681

 
30
 
8,901

 
25
 
11,588

 
29
Total oil production (BOE/D)
31,456

 
80
 
26,296

 
74
 
31,154

 
79
Natural gas production (Mcf/D)
48,436

 
20
 
54,271

 
26
 
51,132

 
21
Total (BOE/D)(1)
39,529

 
100
 
35,341

 
100
 
39,676

 
100
Oil and natural gas, per BOE:
 
 
 
 
 
 
 
 
 
 
 
Average realized sales price
$
74.91

 
 
 
$
69.07

 
 
 
$
75.27

 
 
Average sales price including cash derivative settlements
$
75.58

 
 
 
$
70.40

 
 
 
$
75.95

 
 
Oil, per BOE:
 
 
 
 
 
 
 
 
 
 
 
Average WTI price
$
94.17

 
 
 
$
93.35

 
 
 
$
94.36

 
 
Price sensitive royalties(2)
(2.64
)
 
 
 
(3.55
)
 
 
 
(2.81
)
 
 
Location differential and other(3)
(4.00
)
 
 
 
(0.51
)
 
 
 
(1.25
)
 
 
Oil derivatives non-cash amortization(4)

 
 
 
(1.12
)
 
 
 

 
 
Oil revenue
$
87.53

 
 
 
$
88.17

 
 
 
$
90.30

 
 
Add: Oil derivatives non-cash amortization(4)

 
 
 
1.12

 
 
 

 
 
Oil derivative cash settlements(5)
0.70

 
 
 
0.79

 
 
 
0.89

 
 
Average realized oil price
$
88.23

 
 
 
$
90.08

 
 
 
$
91.19

 
 
Natural gas price:
 
 
 
 
 
 
 
 
 
 
 
Average Henry Hub price per MMBtu
$
4.10

 
 
 
$
2.21

 
 
 
$
3.34

 
 
Conversion to Mcf
0.28

 
 
 
0.15

 
 
 
0.22

 
 
Natural gas derivatives non-cash amortization(4)

 
 
 
0.03

 
 
 

 
 
Location differential and other
(0.29
)
 
 
 
(0.11
)
 
 
 
(0.09
)
 
 
Natural gas revenue per Mcf
$
4.09

 
 
 
$
2.28

 
 
 
$
3.47

 
 
Add: Natural gas derivatives non-cash amortization(4)

 
 
 
(0.03
)
 
 
 

 
 
Natural gas derivative cash settlements(5)
0.09

 
 
 
(0.03
)
 
 
 
(0.01
)
 
 
Average realized natural gas price per Mcf
$
4.18

 
 
 
$
2.22

 
 
 
$
3.46

 
 
__________________________________
(1)
Oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of oil.
(2)
Our Formax property in SMWSS—Steam Floods is subject to a price-sensitive royalty burden. The royalty is 53% of the amount of the heavy oil posted price above the 2013 base price of $17.78 per barrel as long as we maintain a minimum steam injection level. We met the steam injection level in the second quarter of 2013 and expect to meet the requirement going forward. The base price escalates at 2% annually and will be $18.14 in 2014.
(3)
In California, the per barrel oil posting differential at June 30, 2013 was $1.58, ranged from $1.58 to $8.98 during the second quarter of 2013 and averaged $5.05 during the second quarter of 2013. In Utah, the per barrel oil posting differential during the second quarter of 2013 was ($16.50).
(4)
Non-cash amortization of accumulated other comprehensive loss (AOCL) resulting from discontinuing hedge accounting effective January 1, 2010. Recorded in the Condensed Statements of Operations under the caption oil and natural gas sales. At December 31, 2012, the entire balance of AOCL had been reclassified into earnings.
(5)
Cash settlements on derivatives are recorded in the Condensed Statements of Operations under the caption realized and unrealized gain on derivatives, net.

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The following table sets forth selected operating data for the six months ended:

 
June 30, 2013
 
%
 
June 30, 2012
 
%
Heavy oil production (BOE/D)
19,672

 
50
 
17,201

 
49
Light oil production (BOE/D)
11,634

 
29
 
8,495

 
25
Total oil production (BOE/D)
31,306

 
79
 
25,696

 
74
Natural gas production (Mcf/D)
49,777

 
21
 
55,188

 
26
Total (BOE/D)(1)
39,602

 
100
 
34,894

 
100
Oil and natural gas, per BOE:
 
 
 
 
 
 
 
Average realized sales price
$
75.09

 
 
 
$
71.68

 
 
Average sales price including cash derivative settlements
$
75.76

 
 
 
$
72.40

 
 
Oil, per BOE:
 
 
 
 
 
 
 
Average WTI price
$
94.26

 
 
 
$
98.15

 
 
Price sensitive royalties(2)
(2.73
)
 
 
 
(3.89
)
 
 
Location differential and other(3)
(2.65
)
 
 
 
(1.04
)
 
 
Oil derivatives non-cash amortization(4)

 
 
 
(1.13
)
 
 
Oil revenue
$
88.88

 
 
 
$
92.09

 
 
Add: Oil derivatives non-cash amortization(4)

 
 
 
1.13

 
 
Oil derivative cash settlements(5)
0.79

 
 
 
(1.11
)
 
 
Average realized oil price
$
89.67

 
 
 
$
92.11

 
 
Natural gas price:
 
 
 
 
 
 
 
Average Henry Hub price per MMBtu
$
3.72

 
 
 
$
2.47

 
 
Conversion to Mcf
0.26

 
 
 
0.17

 
 
Natural gas derivatives non-cash amortization(4)

 
 
 
0.01

 
 
Location differential and other
(0.20
)
 
 
 
(0.21
)
 
 
Natural gas revenue per Mcf
$
3.78

 
 
 
$
2.44

 
 
Add: Natural gas derivatives non-cash amortization(4)

 
 
 
(0.01
)
 
 
Natural gas derivative cash settlements(5)
0.03

 
 
 
0.45

 
 
Average realized natural gas price per Mcf
$
3.81

 
 
 
$
2.88

 
 
__________________________________
(1)
Oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of oil.
(2)
Our Formax property in SMWSS—Steam Floods is subject to a price-sensitive royalty burden. The royalty is 53% of the amount of the heavy oil posted price above the 2013 base price of $17.78 per barrel as long as we maintain a minimum steam injection level. We met the steam injection level in the second quarter of 2013 and expect to meet the requirement going forward. The base price escalates at 2% annually and will be $18.14 in 2014.
(3)
In California, the per barrel oil posting differential at June 30, 2013 was $1.58, ranged from $1.58 to $11.02 during the first six months of 2013 and averaged $7.53 during the first six months of 2013. In Utah, the per barrel oil posting differential at June 30, 2013 was ($16.50), ranged from ($14.50) to ($16.50) during the first six months of 2013 and averaged ($16.09) during the first six months of 2013.
(4)
Non-cash amortization of AOCL resulting from discontinuing hedge accounting effective January 1, 2010. Recorded in the Condensed Statements of Operations under the caption oil and natural gas sales. At December 31, 2012, the entire balance of AOCL had been reclassified into earnings.
(5)
Cash settlements on derivatives are recorded in the Condensed Statements of Operations under the caption realized and unrealized gain on derivatives, net.



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The following table sets forth results of operations (in thousands except per share data) for the three month periods ended:


June 30, 2013

June 30, 2012

2Q12 to 2Q13
Change

March 31, 2013

1Q13 to 2Q13
Change
Oil sales
$
256,682


$
210,562

 
22
 %

$
250,777


2
 %
Natural gas sales
18,033


11,219


61
 %

15,995


13
 %
Total oil and natural gas sales
$
274,715


$
221,781


24
 %

$
266,772


3
 %
Electricity sales
9,513


5,860


62
 %

7,589


25
 %
Natural gas marketing
2,255


1,580


43
 %

2,027


11
 %
(Loss) gain on sale of assets


(163
)

(100
)%

23


(100
)%
Interest and other income, net
374


645


(42
)%

475


(21
)%
Total revenues and other income
$
286,857


$
229,703


25
 %

$
276,886


4
 %
Net earnings
$
61,364


$
81,016


(24
)%

$
32,434


89
 %
Diluted earnings per share
$
1.10


$
1.46


(25
)%

$
0.58


90
 %

The following table sets forth results of operations (in thousands except per share data) for the six month periods ended:

 
June 30, 2013
 
June 30, 2012
 
%
Change
Oil sales
$
507,459

 
$
431,015

 
18
 %
Natural gas sales
34,028

 
24,419

 
39
 %
Total oil and natural gas sales
$
541,487

 
$
455,434

 
19
 %
Electricity sales
17,102

 
11,840

 
44
 %
Natural gas marketing
4,282

 
3,439

 
25
 %
Gain on sale of assets
23

 
1,600

 
(99
)%
Interest and other income, net
849

 
1,392

 
(39
)%
Total revenues and other income
$
563,743

 
$
473,705

 
19
 %
Net earnings
$
93,798

 
$
114,914

 
(18
)%
Diluted earnings per share
$
1.68

 
$
2.07

 
(19
)%

Oil and Natural Gas Sales.

Oil and natural gas sales increased $52.9 million, or 24%, to $274.7 million in the second quarter of 2013 compared to the same period in 2012. The increase was primarily due to an increase in oil sales volumes between periods. Our oil sales volume increased 23% in the second quarter of 2013 compared to the same period in 2012, while our natural gas sales volumes decreased 11%. The oil sales volume increase was primarily due to increased oil production from all of our oil properties with the exception of SMWSS—Steam Floods, which declined marginally as expected. Permian oil production in the second quarter of 2013 increased 1,200 BOE/D, or 22%, from the same period in 2012, Uinta oil production increased 1,660 BOE/D, or 52%, Diatomite oil production in the second quarter of 2013 increased 1,765 BOE/D, or 60%, and NMWSS—NSF oil production increased 900 BOE/D, or 52%. The decrease in natural gas sales volumes was primarily due to expected production declines from our E. Texas and Piceance properties, partially offset by increased natural gas production from our other natural gas producing properties. In addition to increased oil production, an 8% increase in the average sales price, primarily due to a 79% increase in realized natural gas prices, partially offset by a decrease in realized oil prices, contributed to the increase in oil and natural gas sales in the second quarter of 2013 from the second quarter of 2012.

Oil and natural gas sales increased $7.9 million, or 3%, to $274.7 million in the second quarter of 2013 compared to the first quarter of 2013. The increase was primarily due to a 6% increase in oil sales volumes between periods and an 18% increase in realized natural gas prices, partially offset by a 4% decrease in natural gas sales volumes between periods. The oil sales volume increase was primarily due to increased oil production from all of our oil properties with the exception of SMWSS—Steam Floods, which declined marginally as expected, and the Permian, which was impacted by curtailment issues. Diatomite oil production in the second quarter of 2013 increased 615 BOE/D, or 15%, from the first quarter of 2013, NMWSS

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—NSF oil production increased 290 BOE/D, or 12%, and Uinta oil production increased 235 BOE/D, or 5%. The decrease in natural gas sales volumes was primarily due to expected field decline in E. Texas and the Piceance.

Oil and natural gas sales increased $86.1 million, or 19%, to $541.5 million in the six months ended June 30, 2013 compared to the same period in 2012. The increase was primarily due to a 22% increase in the oil sales volume between periods, while our natural gas sales volumes decreased 10%. The oil sales volume increase was primarily due to increased oil production from all of our oil properties with the exception of SMWSS—Steam Floods, which declined marginally as expected. Permian oil production in the six months ended June 30, 2013 increased 1,630 BOE/D, or 33%, from the same period in 2012, Uinta oil production increased 1,595 BOE/D, or 50%, Diatomite oil production increased 1,600 BOE/D, or 57%, and oil production for NMWSS—NSF increased 875 BOE/D, or 54%. The decrease in natural gas sales volumes was primarily due to expected production declines from our E. Texas and Piceance properties, partially offset by increased natural gas production from our other properties. In addition to increased oil production, a 5% increase in the average sales price, primarily due to a 55% increase in realized natural gas prices, partially offset by a decrease in realized oil prices, contributed to the increase in oil and natural gas sales in the six months ended June 30, 2013 from the same period in 2012.

Electricity Sales.

The following table sets forth selected results of operations for the periods ended:

 
Three Months Ended
 
Six Months Ended
 
June 30, 2013

June 30, 2012

March 31, 2013
 
June 30, 2013

June 30, 2012
Electricity
 

 

 
 
 
 
 
Electricity sales (in thousands)
$
9,513


$
5,860


$
7,589

 
$
17,102


$
11,840

Operating costs (in thousands)
$
6,337


$
4,256


$
5,296

 
$
11,633


$
9,273

Electric power produced (MWh/D)
1,957


2,061


2,036

 
1,996


2,075

Electric power sold (MWh/D)
1,772


1,882


1,851

 
1,812


1,908

Average sales price per MWh
$
58.98


$
34.22


$
44.77

 
$
51.76


$
34.09

Fuel gas cost per MMBtu (including transportation)
$
3.95


$
2.36


$
3.55

 
$
3.75


$
2.52

Estimated natural gas volumes consumed to produce electricity (MMBtu/D)(1)
14,612


14,924


14,726

 
14,684


15,069

_______________________________________
(1)
Estimate is based on the historical allocation of fuel costs to electricity.

Electricity sales in the second quarter of 2013 increased 62% compared to the second quarter of 2012 primarily due to a 72% increase in the average sales price of electricity, partially offset by a 6% decrease in electric power sold. Electricity operating costs in the second quarter of 2013 increased 49% compared to the second quarter of 2012 largely due to a 67% increase in fuel gas cost, partially offset by a 5% decrease in electric power produced.

Electricity sales increased 25% in the second quarter of 2013 compared to the first quarter of 2013, primarily due to a 32% increase in the average sales price of electricity partially offset by a 4% decrease in electric power sold. Electricity operating costs in the second quarter of 2013 increased 20% compared to the first quarter of 2013 largely due to a 11% increase in fuel gas cost, partially offset by a 4% decrease in electric power produced. 

Electricity sales increased 44% in the six months ended June 30, 2013 compared to the six months ended June 30, 2012 primarily due to a 52% increase in the average sales price of electricity, partially offset by a 5% decrease in electric power sold. Electricity operating costs in the six months ended June 30, 2013 increased 25% compared to the six months ended June 30, 2012 primarily due to a 49% increase in fuel gas cost, partially offset by a 4% decrease in electric power produced.

Electricity Sales Contracts. We sell electricity produced by our cogeneration facilities under long-term contracts approved by the California Public Utilities Commission (CPUC) to two California investor owned utilities (IOUs): Southern California Edison Company (Edison) and Pacific Gas and Electric Company (PG&E). Under these power purchase agreements (PPAs), we are paid an energy payment that reflects the utility's Short Run Avoided Cost (SRAC) of energy plus a capacity payment that reflects a recovery of capital expenditures that would otherwise have been made by the utility. Beginning in 2015, the energy prices we will be paid under the contracts for our Cogen 18 and Cogen 38 facilities will be based on market prices for electricity in California.

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Table of Contents


Our legacy PPAs for our Cogen 42 facilities expired in May 2012, at which time a transition PPA with Edison became effective. The transition PPA will terminate on July 1, 2014, upon the effectiveness of a seven-year contract for our Cogen 42 facilities pursuant to a competitive solicitation (the RFO PPA). 

Our legacy PPA for our Cogen 38 facility expired in March 2012, at which time a transition PPA with PG&E became effective. We intend to participate in future competitive solicitations for the sale of energy and capacity from our Cogen 38 facility, although there is no assurance we will be successful in entering into a new RFO PPA for this facility. Our transition PPA with PG&E will remain in effect until June 2015.

Our legacy PPA with PG&E for our Cogen 18 facility terminated on September 30, 2012 and was replaced with a new Public Utilities Regulatory Policy Act of 1978, as amended (PURPA) PPA with PG&E, effective October 1, 2012, for a term of seven years. Because the rated capacity of our Cogen 18 facility is less than 20 MW, it continues to be eligible for PPAs pursuant to PURPA.

Under the PURPA PPA for our Cogen 18 facility and the transition PPAs for our Cogen 38 and Cogen 42 facilities, we will be paid the CPUC-determined SRAC energy price and a combination of firm and "as-available" capacity payments. Under the RFO PPA for our Cogen 42 facility, we will be paid a negotiated energy and capacity price stipulated in the contract.

The following table summarizes our cogeneration facilities and related contract information as of June 30, 2013:

Facility
 
Type of Contract
 
Purchaser
 
Contract Expiration
Cogen 42
 
Transition
 
Edison
 
Jul 2014(1)
Cogen 18
 
PURPA
 
PG&E
 
Sept 2019
Cogen 38
 
Transition
 
PG&E
 
Jun 2015(2)
__________________________________
(1)
A new seven-year RFO PPA with Edison will be effective on July 1, 2014.
(2)
We anticipate the current contract will be replaced by a long-term contract with a term of up to seven years pursuant to a future competitive solicitation.

Natural Gas Marketing.

We have long-term firm transportation contracts on the Rockies Express, Wyoming Interstate Company, and Ruby pipelines, each with a total average capacity of 35,000 MMBtu/D. Demand charges for our capacity are reflected in operating costs—oil and natural gas production in our Condensed Statements of Operations. Our current production is insufficient to fully utilize this capacity. To optimize our remaining capacity, we purchase third-party natural gas at the market rate in our producing areas and utilize FERC-approved asset management agreements. Sales and purchases of third-party natural gas are recorded under natural gas marketing in the revenues and expenses sections of the Condensed Statements of Operations, respectively. The pre-tax net earnings of natural gas marketing operations for the three months ended June 30, 2013 and 2012 were $0.1 million and $0.2 million, respectively. The pre-tax net earnings of natural gas marketing operations for the six months ended June 30, 2013 and 2012 was $0.2 million and $0.3 million, respectively.

(Loss) Gain on Sale of Assets.

In the first quarter of 2012, we recorded a $1.6 million gain in conjunction with the sale of our Nevada Assets. These gains were recorded in the Condensed Statements of Operations under the caption (loss) gain on sale of assets.

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Table of Contents


Oil and Natural Gas Operating and Other Expenses.

The following table sets forth our operating expenses for the three months ended:

 
Amount Per BOE
 
Amount (in thousands)
 
June 30, 2013
 
June 30, 2012
 
March 31, 2013
 
June 30, 2013
 
June 30, 2012
 
March 31, 2013
Operating costs—oil and natural gas production(1)
$
25.37

 
$
19.41

 
$
24.13

 
$
91,277

 
$
62,426

 
$
86,148

Production taxes
3.06

 
3.01

 
3.02

 
11,004

 
9,690

 
10,784

DD&A—oil and natural gas production
19.42

 
16.18

 
19.07

 
69,839

 
52,026

 
68,084

General and administrative
5.40

 
5.59

 
6.24

 
19,430

 
17,965

 
22,278

Interest expense
6.92