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Continental Resources Reports Net Income Of $1.19 Per Diluted Share For Fourth Quarter 2012

Record Fourth Quarter EBITDAX of $594.5 Million Is 44 Percent Higher Than Final Quarter of 2011

OKLAHOMA CITY, Feb. 27, 2013 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") reported strong growth in cash flow and earnings per share for the fourth quarter of 2012, benefiting from increased crude oil production and strong oil price realizations on sales to premium markets.

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"We completed 2012 with an excellent fourth quarter, and growth momentum continues in 2013," said Harold Hamm, Chairman and Chief Executive Officer. "Production has increased, and realized oil prices have been strong as we market an increased share of our Bakken production to U.S. coastal markets. We've seen a fundamental change in oil markets with the significant increase in rail transportation capacity out of the Bakken. Improved differentials and lower operated well costs as we continue to drill and complete projects more efficiently point to continued strong cash flow in 2013."

Significant fourth quarter and full-year 2012 accomplishments included:

  • Net income of $1.19 per diluted share for the fourth quarter of 2012, compared with a net loss of $0.62 per diluted share for the fourth quarter of 2011;
  • Full-year 2012 net income of $739.4 million, or $4.07 per diluted share, a 72 percent increase compared with net income of $429.1 million, or $2.41 per diluted share, for 2011;
  • Record EBITDAX for the fourth quarter of 2012, which was 44 percent higher than the fourth quarter of 2011 and 21 percent higher than the third quarter of 2012;
  • Record production of 106,831 barrels of oil equivalent per day (Boepd) for the fourth quarter of 2012, a 42 percent increase from fourth quarter 2011 production.

Total production in February 2013 is on track to exceed 120,000 Boepd.

As a result of the Company's improved differential to NYMEX, Continental has reduced its 2013 oil differential guidance range to $5 to $7 per barrel, compared with previous guidance of $8 to $11.

Continental reported net income of $220.5 million, or $1.19 per diluted share, for the fourth quarter of 2012. Net income for the quarter included several non-recurring items, including a $42.7 million after-tax gain on sale of assets and a $4.3 million non-cash unrealized gain on derivatives. Partially offsetting these items were two after-tax adjustments – a charge of $18.1 million for property impairments and a small charge related to the relocation of the Company's headquarters to Oklahoma City. Without these items, adjusted net income for fourth quarter 2012 was $191.8 million, or $1.04 per diluted share, an increase of 18 percent compared with adjusted net income per share of $0.88 per diluted share for the fourth quarter of 2011.

Continental reported full-year 2012 net income of $739.4 million, or $4.07 per diluted share, an increase of 72 percent over net income of $429.1 million, or $2.41 per diluted share, for 2011. Adjusted net income for 2012 was $3.36 per diluted share, without the effects of gains on sales of assets, non-cash unrealized gains on derivatives, property impairment charges and relocation expenses. For the reconciliation to U.S. GAAP earnings per share, see "Non-GAAP Financial Measures – Adjusted earnings per share" at the end of this press release.

Continental reported fourth quarter 2012 EBITDAX of $594.5 million, an increase of 44 percent compared with EBITDAX of $411.9 million for the fourth quarter of 2011.

Full-year 2012 EBITDAX was $2.0 billion, a 51 percent increase from EBITDAX of $1.3 billion for 2011. For the Company's definition and reconciliation of EBITDAX to net income and operating cash flows, see "Non-GAAP Financial Measures – EBITDAX" at the end of this press release.

Crude oil accounted for 72 percent of the Company's fourth quarter 2012 production, compared with 70 percent of full-year 2012 production. The balance of Continental's production is natural gas and natural gas liquids.

Continental reported oil and natural gas sales of $670.4 million for the fourth quarter of 2012, compared with $508.3 million for the fourth quarter of 2011, representing a 32 percent increase.

Continental's blended sales price was $68.89 per barrel of oil equivalent (Boe) in the fourth quarter of 2012, comprised of average prices of $84.99 per barrel of crude oil and $4.82 per thousand cubic feet (Mcf) for natural gas. The Company's fourth quarter 2012 average price for crude oil does not include the effect of a $2.7 million pre-tax realized gain on derivatives, but does include transportation, gathering and marketing expenses. In the fourth quarter of 2011, the Company's blended sales price was $72.60 per Boe.

Production expense per Boe was $5.90 for the fourth quarter of 2012, compared with $5.73 per Boe for the fourth quarter of 2011. As previously announced, the Company delayed a number of fourth-quarter well completions to stay within its 2012 capital expenditures budget. Deferred production contributed to higher per-Boe expenses for the fourth quarter. At year-end 2012, Continental had an inventory of 122 net wells drilling, completing or waiting on completion, compared with 62 net wells at year-end 2011.

As previously announced, another key 2012 achievement was the Company's 54 percent increase in proved reserves to 785 million barrels of oil equivalent at December 31, 2012.

At December 31, 2012, Continental's balance sheet included approximately $36 million in cash and cash equivalents and $3.5 billion in total debt, which included $595 million borrowed under the Company's revolving credit facility. Continental's revolving credit facility includes $1.5 billion in bank commitments and a borrowing base of $3.25 billion.  Exploration and production (E&P) capital expenditures for 2012 were $3.0 billion, of which 71 percent was allocated to Bakken exploration and development. The Company also spent an additional $1.3 billion acquiring producing and non-producing properties, primarily in the Bakken and in SCOOP plays, representing considerable value in terms of future drilling opportunities.

Based on current production guidance, approximately 77 percent of forecasted 2013 crude oil production and approximately 33 percent of forecasted 2013 natural gas production is hedged.  Further details on the Company's 2013, 2014 and 2015 derivative positions can be found in Continental's Form 10-K for the year ended December 31, 2012.    

John D. Hart, Senior Vice President and Chief Financial Officer, added, "Our EBITDAX and net earnings results were very strong for the fourth quarter 2012 and the full year.  Financially, we ended the year in a position of strength, closed a bolt-on Bakken acquisition, had ample liquidity, and exited 2012 with a debt-to-EBITDAX ratio of 1.8, in line with our target we discussed with investors at our October 2012 Investors Day." 

Improved Oil Differential Impacts 2013 Guidance

Continental's oil differential was $3.21 per barrel for the fourth quarter 2012, a decrease of $6.24 from the third quarter of 2012. Continental's oil differential reflects an all-in average of transportation costs from well-head to end market and differential discounts for all of its operated and non-operated production.  

The improvement since mid-2012 in differentials primarily reflects Continental's ability to market and deliver oil to premium markets throughout the United States, with an increased reliance on rail transportation versus pipeline. In December 2012, 72 percent of the Company's operated Bakken production was transported to market by rail, compared with only 41 percent in January 2012.

"Lower differentials and more efficient access to premium markets are key factors driving higher cash margins and profitability," said Rick Bott, President and Chief Operating Officer. "We now expect average oil differentials in 2013 will be $5 to $7 per barrel.

"2012 saw fundamental changes in U.S. oil markets, with Bakken crude shipped directly to all major U.S. refining centers and making progress, we believe, toward becoming a national benchmark crude," he said. "Refiners on the East, Gulf and West coasts value the consistently high quality of sweet Bakken crude and the fact that supply from the basin continues to grow.

"Consistent with our strategy to develop versatility in transportation modes and markets, Continental was a first mover in establishing new markets on all three U.S. coasts for Bakken crude. Because of our size, flexibility and growth trajectory, we are one of only a few companies capable of providing a reliable, growing supply of this consistently high-quality crude to major refinery customers," Mr. Bott said. "End-users in turn continue to build pipe and rail off-loading facilities at delivery points throughout the nation to take advantage of the increased visibility of crude oil production growth from the Bakken."

Well Costs Improvement

Continental also achieved progress in reducing average drilling and completion costs per well in the fourth quarter of 2012.

This resulted from faster cycle times, lower stimulation costs per stage, and increased pad drilling in the Bakken. The Company drilled 259 gross wells in the Bakken with an average of 21 rigs during 2012, or 12 wells per rig for the year. This compares with an average of seven wells per rig in 2011. A key contributor to this improvement was Continental's 35 percent improvement in single well spud-to-spud cycle times last year, compared with 2011.

As another example of reduced well costs, Continental recently completed its six-well Florida-Alpha project for $46.8 million, or less than $8 million per well. This compares with an average ECO-Pad® well cost of $8.5 million per well in 2012, as disclosed at Continental's Investors Day in October 2012. Two-thirds of the Company's operated rigs in the Bakken are currently working on multi-well pad projects.

"Along with our continued focus on operational excellence and safety, Continental was the first to envision the utility of multi-well pad drilling in the Bakken and the efficiencies it could generate," Mr. Bott said. "Pad drilling is the future for full-field development, and, given our transition to more pads, we are on track to meet our goal of reducing average operated well costs in the Bakken to $8.2 million per well by year-end 2013, a reduction of $1 million per well in early 2012."

Operating Highlights

Continental's operating and financial results for 2012 were in line with its guidance for the year.














Three months ended December 31,


Year ended December 31,


2012


2011


2012


2011

Average daily production:












Crude oil (Bbl per day)


76,449



53,905



68,497



45,121

Natural gas (Mcf per day)


182,289



127,883



174,521



100,469

Crude oil equivalents (Boe per day)


106,831



75,219



97,583



61,865

Average sales prices: (1)












Crude oil ($/Bbl)

$

84.99


$

89.24


$

84.59


$

88.51

Natural gas ($/Mcf)


4.82



4.97



4.20



5.24

Crude oil equivalents ($/Boe)


68.89



72.60



66.83



73.05

Production expenses ($/Boe) (1)


5.90



5.73



5.49



6.13

General and administrative expenses ($/Boe) (1)(2)

3.60



3.02



3.42



3.23

Net income (loss) (in thousands) 


220,511



(112,064)



739,385



429,072

Diluted net income (loss) per share


1.19



(0.62)



4.07



2.41

EBITDAX (in thousands)(3)


594,452



411,919



1,963,123



1,303,959

(1)

Average sales prices and per unit expenses have been calculated using sales volumes and exclude any effect of derivative transactions.

(2)

General and administrative expenses ($/Boe) include non-cash equity compensation expense of $0.85 per Boe and relocation expense of $0.05 per Boe for the three months ended December 31, 2012 compared to non-cash equity compensation expense of $0.69 per Boe and relocation expense of $0.25 per Boe for the three months ended December 31, 2011.  For the year ended December 31, 2012, general and administrative expenses include non-cash equity compensation expense of $0.82 per Boe and relocation expense of $0.22 per Boe compared to non-cash equity compensation expense of $0.73 per Boe and relocation expense of $0.14 per Boe for the year ended December 31, 2011.

(3)

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of Accounting for Derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP. Reconciliations of net income and operating cash flows to EBITDAX are provided subsequently under the header Non-GAAP Financial Measures.

 

The following table presents the Company's average daily production by region for the periods presented.



4Q


3Q


4Q

Boe per day


2012


2012


2011

North Region:







North Dakota Bakken


59,019


55,918


35,565

Montana Bakken


8,503


6,535


5,678

Red River Units 


14,716


14,916


15,246

Other


967


1,343


964








South Region:







NW Cana Woodford


9,716


11,395


7,949

SCOOP Woodford


7,123


5,108


1,871

Arkoma Woodford 


3,225


4,061


3,688

Other 


2,556


2,590


3,080

East Region


1,006


1,098


1,178

Total


106,831


102,964


75,219

In December 2012 Continental sold its producing crude oil and natural gas properties in its East Region.

Bakken Production Continues to Grow

Continental, the leading liquids producer in the Rocky Mountain region, reported Bakken production of 67,522 Boepd for the fourth quarter of 2012, a 64 percent increase compared with the fourth quarter of 2011.

Bakken production as a percent of total production continued to increase over the past year, accounting for 63 percent of the Company's total production in the fourth quarter of 2012, compared with 55 percent in the fourth quarter of 2011.

Continental almost doubled its proved reserves in the Bakken in 2012, ending the year with 564 MMBoe in proved reserves at December 31, 2012.

The Company participated in 51 net (135 gross) operated and non-operated wells in the Bakken during the fourth quarter of 2012.

In terms of operated wells, Continental completed 42 net (55 gross) wells in the Bakken in the fourth quarter of 2012, with 30 net (42 gross) wells in North Dakota and the remainder in Montana.

Initial well results continue to meet Continental's expectations. In North Dakota, Company-operated wells completed during the fourth quarter averaged 1,187 Boepd, while Montana wells averaged 655 Boepd in their initial one-day test-periods. These results are consistent with the Company's estimated ultimate recovery (EUR) models of 603,000 Boe for North Dakota wells and 430,000 Boe for Montana wells.

Continental's Lower Three Forks exploratory program is underway with one well drilling and seven wells completing. The 2013 program, recently expanded to 20 wells, is designed to establish the productive extent of the lower Three Forks benches, building on the success of the Charlotte 2-22H and 3-22H wells, the initial producing wells in the second and third benches in the field, respectively.

Its most recent completion in this program was the Angus 2-9H-2 (85% WI), which flowed 1,556 Boepd at 3,200 psi in its initial one-day test period. The Angus 2-9H-2 is the Company's second well to be completed in the second bench of the Three Forks formation. The well is a significant step-out, located 27 miles northeast of the Charlotte 2-22H.

The Charlotte 2-22H has produced 108 MBoe in approximately 14 months. The Charlotte 3-22H (TF3) has produced 35 MBoe in its initial three months. The wells are performing in line with typical Bakken/Three Forks first-bench wells.

In the future, the Company expects to report quarterly on the exploratory Lower Three Forks program.

Lower Three Forks Exploration Well Status

Zone

Drilling

Completing

Producing

To Be Drilled

Total

TF1


1


3

4

TF2


3

2

6

11

TF3

1

2

1

1

5

TF4


1


1

2

Total

1

7

3*

11

22

*Total producing wells include the Charlotte 2-22H and 3-22H, which were completed prior to the 2013 Lower Three Forks Exploration program, and the recently completed Angus 2-9H-2.

The Company's other Bakken exploration/appraisal initiative involves four pilot density projects to test 320-acre and 160-acre spacing in the Middle Bakken and first three benches of the Three Forks. The Company plans to complete 47 gross wells in the pilot density program, arrayed to help determine the optimum well spacing and pattern to maximize the ultimate recovery of oil from the multiple Bakken and Three Forks reservoirs.

Continental has initiated its first 320-acre pilot density project, with three wells currently being completed and two more being drilled. The 160-acre pilot and the next 320-acre pilot are scheduled to spud by mid-2013, with the third 320-acre pilot planned to spud in the third quarter of 2013.

"These are aggressive pilot projects over a wide area in the field," Mr. Bott said. "We plan to spend the next 18 months drilling and completing the 47 wells, with production coming on line starting in late 2013. All wells in the program should be producing in the first quarter of 2014.These exploration and appraisal programs should help determine the ultimate recovery of the field and drive valuations higher by accelerated de-risking and down-spacing."

Continental increased its Bakken acreage position to approximately 1,140,000 net acres at year-end 2012, up 24 percent from year-end 2011, solidifying its position as the largest leasehold owner in the play.

The Company plans to complete or participate in completing 226 net (558 gross) wells in the Bakken in 2013, including both operated and non-operated wells. The Company currently has 21 operated rigs in the play, with 16 drilling in North Dakota and five in Montana.

SCOOP/Northwest Cana Woodford Results

Continental produced 7,123 Boepd in the South Central Oklahoma Oil Province (SCOOP) in the fourth quarter of 2012, a 281 percent increase compared with fourth quarter production last year and a 39 percent increase compared with the third quarter 2012 production.

Fourth quarter production in the Northwest Cana (Blaine and Dewey counties) declined from the third quarter of 2012 due to reduced drilling activity as the Company refocused capital to the more oily SCOOP.

The Company participated in 10 net (17 gross) wells in SCOOP during the fourth quarter of 2012. Twelve gross wells were drilled in the condensate fairway and five in the oil fairway. The new wells' average initial production rates were in line with or better than the average for earlier wells in the two fairways.

"Although SCOOP is in the early stages of development, we are very pleased with the repeatability we are seeing within each of the fairways and with the wells' strong rates of return, which are comparable to the Bakken," said Jack Stark, Senior Vice President of Exploration. "We're continuing to extend the limits of the play and to drill to hold our acreage."

Continental-operated wells completed in the condensate fairway since the beginning of fourth quarter 2012 have included:

  • Cosby 1-13H (84% WI), which produced 1,761 Boepd (23% crude oil) in its initial one-day test period;
  • Lowrance 1-10H (73% WI), which produced 1,580 Boepd (38% crude oil) in its initial one-day test period;
  • Wooten 1-28H (64% WI), which produced 1,103 Boepd (25% crude oil) in its initial one-day test period.

Fourth quarter operated wells in the oil fairway included:

  • Elliott 1-35H (94% WI), which produced 633 Boepd (67% crude oil) in its initial one-day test period;
  • Nightengale 1-16H (71% WI), which produced 523 Boepd (78% crude oil) in its initial one-day test period.

The new SCOOP wells are producing substantial natural gas liquids. The combined total of oil and natural gas liquids typically ranges from 45 percent to 80 percent of production for these wells.

Continental had approximately 218,000 net acres leased in SCOOP as of December 31, 2012, but has since increased its position to approximately 245,000 net acres. Continental believes its acreage is evenly split between the condensate and oil fairways. The Company plans to complete or participate in completing 41 net (90 gross) wells in SCOOP in 2013, including both operated and non-operated wells. The Company currently has 6 operated rigs in SCOOP and plans to increase to 12 rigs over the course of this year.

Current 2013 Guidance                                         




Production growth range


35% to 40%

Capital expenditures*


$3.6 billion




Price differentials:



     WTI crude oil (per barrel of oil)**


$5.00 to $7.00

     Henry Hub natural gas (per Mcf)


+$1.00 to +$1.50




Operating expenses:



     Production expense per Boe


$5.20 to $5.60

     Production tax as a percent of oil



          and gas revenues***


8% to 9%

     DD&A per Boe


$19.00 to $21.00

     G&A expense per Boe****


$2.20 to $2.70

     Non-cash compensation per Boe


$0.70 to $0.90




Income tax rate**


37%

Deferred taxes


90% to 95%


*Excludes acquisition capital expenditures

**Updated with this press release

***Does not include other expenses, such as natural gas transportation fees, which could represent another 1%.

****Excludes non-cash equity compensation of $0.70 to $0.90 per Boe

Conference Call Information

Continental Resources plans to host a conference call to discuss fourth quarter and full-year 2012 results on Thursday, February 28, 2013, at 10 a.m. ET (9 a.m. CT). Those wishing to listen to the conference call may do so via the Company's web site at www.CLR.com or by phone:

Time and date:        

10 a.m. ET


Thursday, February 28, 2013



Dial in:             

888 680 0878

Intl. dial in:         

617 213 4855

Pass code:       

14983127

A replay of the call will be available for 30 days on the Company's web site or by dialing:

Replay number:

888 286 8010

Intl. replay 

617 801 6888

Pass code:

29374525

Callers who wish to pre-register for the call may go to:
https://www.theconferencingservice.com/prereg/key.process?key=PCPLHQ7VN

Conference Presentations

Continental management is currently scheduled to present at the following research conferences. Presentation materials will be available on the Company's web site on the day of the presentation.

March 4

2013 Raymond James 34th Annual Institutional Investors Conference, Orlando

March 18

2013 Howard Weil 41st Annual Energy Conference, New Orleans

About Continental Resources

Continental Resources is a Top 10 petroleum liquids producer in the United States. In October 2012, the Company announced a new five-year plan to triple production and proved reserves by year-end 2017. The Company's growth plan is based on developing its industry-leading leasehold in the nation's premier oil play, the Bakken of North Dakota and Montana, as well as its position in the SCOOP and Northwest Cana plays of Oklahoma. The company reported total revenues of $2.6 billion for 2012. Continental is headquartered in Oklahoma City. Visit www.CLR.com for more information.

Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995

This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes that the expectations reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. When considering forward-looking statements, readers should keep in mind the risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors included in the Company's Annual Report on Form 10-K for the year ended December 31, 2012, registration statements and other reports filed from time to time with the Securities and Exchange Commission (SEC), and other announcements the Company makes from time to time.

The Company cautions readers that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Part I, Item 1A. Risk Factors in the Company's Annual Report on Form 10-K for the year ended December 31, 2012, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that the Company, or persons acting on its behalf, may make.

Except as otherwise required by applicable law, the Company disclaims any duty to update any forward-looking statements to reflect events or circumstances after the date of this press release.

CONTACTS: Continental Resources, Inc.

Investors 

Media

Warren Henry, VP Investor Relations

Kristin Miskovsky, VP Public Relations

405-234-9127   

405-234-9480

[email protected]                  

[email protected]

 

Consolidated Statements of Income














Three months ended December 31,


Year ended December 31,


2012


2011


2012


2011

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$

670,438


$

508,309


$

2,379,433


$

1,647,419

Gain (loss) on derivative instruments, net


9,639



(402,539)



154,016



(30,049)

Crude oil and natural gas service operations


8,895



8,348



39,071



32,419

Total revenues


688,972



114,118



2,572,520



1,649,789













Operating costs and expenses:












Production expenses


57,399



40,146



195,440



138,236

Production taxes and other expenses


65,558



44,495



228,438



144,810

Exploration expenses


5,755



6,260



23,507



27,920

Crude oil and natural gas service operations


7,525



7,022



32,248



26,735

Depreciation, depletion, amortization and accretion

192,271



126,663



692,118



390,899

Property impairments


29,121



42,143



122,274



108,458

General and administrative expenses 


35,031



21,121



121,735



72,817

Gain on sale of assets, net


(68,908)



(5,451)



(136,047)



(20,838)

Total operating costs and expenses


323,752



282,399



1,279,713



889,037

Income (loss) from operations


365,220



(168,281)



1,292,807



760,752

Other income (expense):












Interest expense


(45,534)



(19,985)



(140,708)



(76,722)

Other 


817



890



3,097



3,415



(44,717)



(19,095)



(137,611)



(73,307)

Income (loss) before income taxes


320,503



(187,376)



1,155,196



687,445

Provision (benefit) for income taxes


99,992



(75,312)



415,811



258,373

Net income (loss)

$

220,511


$

(112,064)


$

739,385


$

429,072

Basic net income (loss) per share

$

1.20


$

(0.62)


$

4.08


$

2.42

Diluted net income (loss) per share

$

1.19


$

(0.62)


$

4.07


$

2.41

 

 

Consolidated Balance Sheets



December 31,


December 31,


2012


2011

Assets

In thousands

Current assets

$

946,783


$

936,373

Net property and equipment


8,105,269



4,681,733

Other noncurrent assets


87,957



27,980

Total assets

$

9,140,009


$

5,646,086







Liabilities and shareholders' equity






Current liabilities

$

1,125,865


$

1,111,801

Long-term debt


3,537,771



1,254,301

Other noncurrent liabilities


1,312,674



971,858

Total shareholders' equity


3,163,699



2,308,126

Total liabilities and shareholders' equity

$

9,140,009


$

5,646,086

 

 

Consolidated Statements of Cash Flows



Year ended December 31, 


2012


2011


In thousands

Net income 

$

739,385


$

429,072

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






Non-cash expenses


905,695



748,792

Changes in assets and liabilities


(13,015)



(109,949)

Net cash provided by operating activities


1,632,065



1,067,915







Net cash used in investing activities


(3,903,370)



(2,004,714)







Net cash provided by financing activities


2,253,490



982,427







Net change in cash and cash equivalents


(17,815)



45,628

Cash and cash equivalents at beginning of period


53,544



7,916

Cash and cash equivalents at end of period

$

35,729


$

53,544

Non-GAAP Financial Measures

EBITDAX

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP.

Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income and operating cash flows in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.

EBITDAX should not be considered as an alternative to, or more meaningful than, net income or operating cash flows as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.

We believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Our credit facility requires that we maintain a total funded debt to EBITDAX ratio of no greater than 4.0 to 1.0 on a rolling four-quarter basis. This ratio represents the sum of outstanding borrowings and the letters of credit under our credit facility plus our note payable and Senior Note obligations, divided by total EBITDAX for the most recent four quarters. Our credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by us. The following table provides a reconciliation of our net income to EBITDAX for the periods presented.


Three months ended December 31,


Year ended December 31,


2012


2011


2012


2011


in thousands

Net income (loss)

$

220,511


$

(112,064)


$

739,385


$

429,072

Interest expense


45,534



19,985



140,708



76,722

Provision (benefit) for income taxes


99,992



(75,312)



415,811



258,373

Depreciation, depletion, amortization and accretion


192,271



126,663



692,118



390,899

Property impairments


29,121



42,143



122,274



108,458

Exploration expenses


5,755



6,260



23,507



27,920

Impact from derivative instruments:












Total (gain) loss on derivatives, net


(9,639)



402,539



(154,016)



30,049

Total realized gain (loss) (cash flow) on derivatives, net


2,655



(3,125)



(45,721)



(34,106)

Non-cash (gain) loss on derivatives, net


(6,984)



399,414



(199,737)



(4,057)

Non-cash equity compensation


8,252



4,830



29,057



16,572

EBITDAX

$

594,452


$

411,919


$

1,963,123


$

1,303,959

 

The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.


Year ended December 31,


2012


2011


in thousands

Net cash provided by operating activities

$

1,632,065


$

1,067,915

Current income tax provision


10,517



13,170

Interest expense


140,708



76,722

Exploration expenses, excluding dry hole costs


22,740



19,971

Gain on sale of assets, net


136,047



20,838

Excess tax benefit from stock-based compensation


15,618



-

Other, net


(7,587)



(4,606)

Changes in assets and liabilities


13,015



109,949

EBITDAX

$

1,963,123


$

1,303,959

Adjusted earnings per share

Our presentation of adjusted earnings per share that excludes the effect of certain items is a non-GAAP financial measure. Adjusted earnings per share represents diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and corporate relocation expenses. Management believes this measure provides useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to period. In addition, management believes this measure is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and nonrecurring transactions. Adjusted earnings per share should not be considered in isolation or as a substitute for earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share.









Three months ended December 31, 









2012


2011

In thousands, except per share data


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS

Net income (loss) (GAAP)


$ 220,511


$        1.19


$(112,064)


$       (0.62)

Adjustments, net of tax:










Non-cash (gain) loss on derivatives, net


(4,331)


(0.02)


247,237


1.37


Property impairments


18,054


0.10


26,087


0.14


Gain on sale of assets, net


(42,723)


(0.23)


(3,374)


(0.02)


Corporate relocation expenses


290


-


1,076


0.01



Adjusted net income (Non-GAAP)


$ 191,801


$        1.04


$ 158,962


$        0.88



Weighted average diluted shares outstanding


184,603




180,343





Adjusted diluted net income per share (Non-GAAP)


$      1.04




$      0.88











Year ended December 31, 









2012


2011

In thousands, except per share data


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS

Net income (GAAP)


$ 739,385


$        4.07


$ 429,072


$        2.41

Adjustments, net of tax:










Non-cash gain on derivatives, net


(123,838)


(0.68)


(2,511)


(0.01)


Property impairments


75,810


0.41


67,136


0.37


Gain on sale of assets, net


(84,349)


(0.46)


(12,899)


(0.07)


Corporate relocation expenses


4,862


0.02


1,974


0.01



Adjusted net income (Non-GAAP)


$ 611,870


$        3.36


$ 482,772


$        2.71



Weighted average diluted shares outstanding


181,846




178,230





Adjusted diluted net income per share (Non-GAAP)


$      3.36




$      2.71



SOURCE Continental Resources

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