Bill Barrett Corporation Reports 2011 Results – Cash Flow of $478 million and Proved Reserves up 22%
DENVER, Feb. 23, 2012 /PRNewswire/ — Bill Barrett Corporation (NYSE: BBG) today reported full-year 2011 operating results highlighted by:
- Natural gas and oil production growth, up 11% to 106.8 Bcfe
- Proved reserve growth, up 22% to 1.4 Tcfe or 331% production replacement
- Discretionary cash flow up, at $478.2 million or $10.12 per diluted common share
- Adjusted net income up, at $84.0 million or $1.78 per diluted common share
Chairman, Chief Executive Officer and President Fred Barrett commented: “In 2011, excellent execution in operations delivered sizable growth in reserves and a meaningful transition to focus on oil and natural gas liquids (“NGLs”). We increased total proved reserves 22% while increasing the oil component 135%. We delivered $10.12 per share in discretionary cash flow and solid adjusted EPS of $1.78 (non-GAAP measures, see “Discretionary Cash Flow Reconciliation” and “Adjusted Net Income Reconciliation” below). As we enter a challenging price environment for natural gas in 2012, I want to reiterate our success in 2011 towards better balancing the commodities mix in our portfolio with 27% (see “Disclosure Statements” below) of production sold as oil and NGLs, and we expect to increase that in 2012.
“Our 2012 capital program is firmly targeting oil growth and natural gas production that receives the revenue benefit from processing for NGLs. In 2012, we will focus on further increasing scale at the Uinta Oil Program with a 3.5 rig program for the year and building our Denver-Julesburg acquisition into a full scale development program. We also have a number of exciting exploration prospects to be tested, mostly during the first half of the year, and all targeting oil and NGLs. We are well positioned to meet the challenges of 2012 with approximately 62% of our projected natural gas production hedged at $4.08 per thousand cubic feet (“Mcf”) on average, a strong balance sheet and the flexibility to modify our capital program in accordance with commodity prices as the year unfolds.”
Natural gas and oil production totaled 106.8 billion cubic feet equivalent (“Bcfe”) in 2011, up 11% from 96.5 Bcfe in 2010. Production growth was predominantly from West Tavaputs, with successful start-up of full-field development, and from the Uinta Oil Program, where the drilling program was expanded from one to three rigs during the year. The Company also drove a 37% increase in oil production, primarily from the Uinta Oil Program and Denver-Julesburg Basin acquisition. Including the effects of the Company’s hedging activities and natural gas liquids recovery, the average realized sales price in 2011 was $7.05 per Mcfe, nearly flat with the 2010 average of $7.07 per Mcfe. The Company’s 2011 commodity hedging program increased its natural gas and oil revenues by net $71.9 million, or $0.68 per Mcfe of production. For the fourth quarter of 2011, production was 29.1 Bcfe, up 20% from 24.2 Bcfe in the fourth quarter of 2010, and the average realized price was $6.96 per Mcfe, up slightly from $6.86 per Mcfe in the fourth quarter of 2010.
Proved reserves at year-end 2011 were 1.365 trillion cubic feet equivalent (“Tcfe”), up 22% from 1.118 Tcfe at year-end 2010. Capital expenditures totaled $987.3 million, including $704.5 million for exploration, development and corporate capital plus $282.8 million for acquisitions.
Discretionary cash flow (a non-GAAP measure, see “Discretionary Cash Flow Reconciliation” below) for 2011 was $478.2 million, or $10.12 per diluted common share, up $11.2 million from 2010. Comparable year-over-year results included higher revenue in 2011 mostly offset by higher cash operating costs and higher interest expense. Discretionary cash flow for the fourth quarter of 2011 was $124.8 million, or $2.66 per diluted common share, up 14% compared with $109.9 million, or $2.41 per diluted common share, in the fourth quarter of 2010.
Net income for 2011 was $30.7 million, or $0.65 per diluted common share, down from $80.5 million, or $1.75 per diluted common share, in 2010. 2011 net income included impairment expenses of $100.3 million, primarily related to an adjustment in the carrying value of coalbed methane natural gas assets in the Powder River Basin taken in the fourth quarter, and dry hole expenses of $13.4 million, mostly related to wells expensed during the third quarter. Adjusted net income for 2011 (a non-GAAP measure, see “Adjusted Net Income Reconciliation” below) was $84.0 million, or $1.78 per diluted common share, compared with $78.6 million, or $1.71 per diluted common share, in 2010. Adjusted net income removes the effect of non-recurring charges such as unrealized derivative gains and losses, impairment expenses, property sales and one-time items. For the fourth quarter of 2011, the Company had a net loss of ($37.8) million or ($0.81) per diluted common share, with the loss attributable to the impairment charges taken in the fourth quarter. Adjusted net income for the fourth quarter of 2011 was $20.6 million or $0.44 per diluted common share.
DEBT AND LIQUIDITY
The Company had $70 million drawn on its revolving credit facility at December 31, 2011. The revolving credit facility has commitments totaling $900.0 million and a borrowing base of $1.1 billion. Deducting an outstanding letter of credit for $26.0 million, the Company had $804.0 million of borrowing capacity at December 31, 2011. The Company expects to draw from its revolving credit facility during 2012 as planned capital expenditures are expected to exceed cash flows from operations. The Company also had $172.5 million in 5% convertible senior notes, $400.0 million in 7.625% senior notes and $250.0 million in 9.875% senior notes outstanding at December 31, 2011. If the 5% convertible senior notes are put to the Company as allowed in March 2012, the Company has sufficient funds available under its revolving credit facility to fund the purchase price of the notes.
OPERATIONS
Production, Wells Spud and Capital Expenditures
The following table lists production, wells spud and total capital expenditures by basin for the three and twelve months ended December 31, 2011:
Three Months ended December Twelve Months ended December
31, 2011 31, 2011
--------------------------- ----------------------------
Average Average
Net Wells Capital Net Wells Capital
Production Spud Expenditures Production Spud Expenditures
Basin (MMcfe/d) (gross) (millions) (MMcfe/d) (gross) (millions)
----- --------- ------- ---------- --------- ------- ----------
Uinta:
UOP 22 17 $47.1 17 49 $250.5
West Tavaputs 102 22 89.5 88 92 269.1
Piceance 138 40 59.7 134 123 209.2
Denver-Julesburg 4 6 22.5 N/A 8 181.7
Powder River
(CBM) 35 0 0.4 36 5 4.1
Other 15 0 35.3 18 10 72.7
----- --- --- ---- --- --- ----
Total 316 85 $254.5 293 287 $987.3
----- --- --- ------ --- --- ------
Capital expenditures totaled $987.3 million for the full year 2011 and $254.5 million in the fourth quarter of 2011. The Company did not have any material divestitures in 2011. The average all-in finding and development cost (a non-GAAP measure, see “Costs Incurred and Reserve Information” below) for 2011 was $16.57 per barrel of oil equivalent (“Boe”), or $13.09 per Boe for the three-year average.
Operating and Drilling Update
The Company anticipates drilling or participating in approximately 380 gross/290 net development wells in 2012. The Company’s development program will focus on growth in oil and liquids-rich production and reserves. In 2012, the Company also plans a robust exploration program that will include the drilling and testing of oil and NGL prospects in the Southern Alberta, Powder River, Denver-Julesburg, Paradox and San Juan Basins. The Company currently has eight rigs drilling at development programs, seven of which are targeting oil and NGLs, and one rig drilling at an oil exploration prospect.
Uinta Basin, Utah
Uinta Oil Program (Blacktail Ridge, Lake Canyon, East Bluebell and South Altamont) -
Current net production is approximately 3,500 barrels of oil equivalent per day (“Boe/d”). The Company expanded the 2011 program from one to three drilling rigs and expects to add a fourth rig mid-year 2012. During 2011, the Company drilled seven successful horizontal wells into the Uteland Butte formation, opening up the opportunity for an expanded horizontal program. Further, the Company expanded its land position in the region through acquisitions in the East Bluebell and South Altamont areas. During 2011, the Company increased the proved reserves in the area by more than 300% to 29 MMBoe, increased its proved, probable and possible reserves in the area by 240% to 131 MMBoe and quadrupled its gross drilling locations. Dependent upon receipt of permits, the Company expects to participate in drilling up to 100 gross wells in the area in 2012, including approximately 30 wells operated by its partner in Lake Canyon. At December 31, 2011, the Company had an approximate 64% working interest in production from 121 gross wells. Depending upon elections to participate by partners, the Company expects to have an average 43% working interest in its 2012 drilling program. The working interests for the 2012 program range from 19% to 100%.
West Tavaputs – Current net production is approximately 104 million cubic feet equivalent per day (MMcfe/d), up from 57 MMcfe/d at this time last year. Following receipt of the Environmental Impact Statement Record of Decision in the fourth quarter of 2010, the Company quickly and efficiently initiated full field development. The 2012 program has been scaled back to one drilling rig as a result of currently low natural gas prices; however, this program remains one of the Company’s largest, long-term development assets having 461 Bcfe of proved reserves, 1.2 Tcfe proved, probable and possible reserves (see “Reserve Disclosure” below) and a multi-year inventory of more than 600 gross drilling locations.
At December 31, 2011, the Company had an approximate 96% working interest in production from 269 gross wells in its West Tavaputs shallow and deep programs. The West Tavaputs program offers growth in the shallow Mesaverde and Wasatch zones as well as upside opportunity through the shallow Green River oil and deeper formations including the Mancos.
Piceance Basin, Colorado
Gibson Gulch – Current net production is approximately 137 MMcfe/d. During 2012, the Company currently plans to operate three rigs in the area. The Gibson Gulch program serves as a “swing area” for the Company as it can substantially modify the drilling program in conjunction with broader capital plans and commodity prices. The Company continues to benefit from its election to process the majority of its Gibson Gulch natural gas production, which exposes the Company to natural gas liquids pricing. Strong NGL pricing drives strong returns from production in this area. The incremental benefit to production revenues related to natural gas liquids was $1.25 per Mcfe to the Company-wide realized price in the fourth quarter and $1.23 per Mcfe for the full year 2011. Gibson Gulch operations offer strong margins due both to low operating costs and the currently higher revenues related to liquids. The program continues to be a key, lower risk development area for the Company.
At December 31, 2011, the Company had an approximate 99% working interest in production from 826 gross wells in its Gibson Gulch program.
Denver-Julesburg Basin, Colorado and Wyoming
Wattenburg and Chalk Bluffs – Current DJ net production is approximately 800 Boe/d. The Company initiated drilling in the area with five vertical wells in the Wattenberg area in the fourth quarter of 2011 and plans to drill an approximate 40-well horizontal program in 2012. The 2012 program is expected to target the Niobrara formation in the Greater Wattenberg development area as well as the Chalk Bluffs and Briggsdale exploration areas. As of December 31, 2011, proved reserves were 7 MMBoe and proved, probable and possible reserves were 23 MMBoe.
At December 31, 2011, the Company had an approximate 91% working interest in production from 216 gross wells.
ADDITIONAL FINANCIAL INFORMATION
Guidance
As previously announced, the Company’s 2012 guidance (please reference “Forward-Looking Statements” below) is as follows. The Company may update guidance as business conditions warrant:
- Capital expenditures of $900 to $1,000 million (before acquisitions, if any), which includes approximately $150 million for exploration and delineation activities.
- Oil and natural gas production of 126 to 130 Bcfe, up 18% to 22% from 2011.
- Lease operating costs per Mcfe of $0.55 to $0.59.
- Gathering, transportation and processing costs per Mcfe of $0.90 to $0.95.
- General and administrative expenses before non-cash stock-based compensation cost per Mcfe of $0.43 to $0.47.
Commodity Hedges Update
It is the Company’s strategy to hedge a portion of its production to reduce the risks associated with unpredictable future commodity prices and to provide predictability for a portion of cash flows in order to support the Company’s capital expenditure program.
For 2012 and 2013, the Company has hedges in place as outlined in the table below. Swap and collar hedge positions are tied to regional sales points and include:
- For 2012, approximately 79.5 Bcfe, or approximately 62% of production, at a weighted average blended floor price of $6.63 per Mcfe. Approximately 62% of natural gas production is hedged.
- For 2013, approximately 47.3 Bcfe at a weighted average blended floor price of $5.62 per Mcfe.
As of February 17, 2012:
SWAPS & COLLARS
===============
Natural Gas /
Period NGLs Oil EQUIVALENT
------ ------------- --- ----------
Volume Price Volume Price Volume Price
MMBtu/d $/MMBtu Bbl/d $/Bbl Mmcfe $/Mcfe
1Q12 183,798 $5.25 4,602 $100.52 17,718 $7.34
2Q12 221,029 $4.39 4,900 $100.63 20,961 $6.36
3Q12 228,342 $4.36 4,900 $100.63 21,803 $6.28
4Q12 195,462 $4.54 4,900 $100.63 19,053 $6.66
1Q13 166,794 $3.82 2,300 $100.50 14,889 $5.25
2Q13 116,774 $3.93 2,300 $100.50 10,916 $5.76
3Q13 116,755 $3.93 2,300 $100.50 11,035 $5.75
4Q13 110,124 $3.96 2,300 $100.50 10,480 $5.86
In addition, the Company has natural gas basis only hedges in place for 2012 of 20,000 MMBtu/d at a basis differential price of ($1.22) per MMBtu. These hedges are not in the money.
2011 FOURTH QUARTER AND FULL YEAR RESULTS WEBCAST AND CONFERENCE CALL
As previously announced, a webcast and conference call will be held later this morning to discuss 2011 results. Please join Bill Barrett Corporation executive management at 12:00 p.m. EST/10:00 a.m. MST for the live webcast, accessed at www.billbarrettcorp.com, or join by telephone by calling 877-299-4454 (617-597-5447 international callers) with passcode 40513373. The webcast will remain available on the Company’s website for approximately 30 days, and a replay of the call will be available through February 28, 2012 at call-in number 888-286-8010 (617-801-6888 international) with passcode 27578683. The Company also has tentatively scheduled its 2012 earnings conference calls for May 3, August 2 and November 1, 2012, typically at noon Eastern time/10:00 a.m. Mountain time.
Annual Report on Form 10-K
The Company plans to file later this morning its Annual Report on Form 10-K for the year ended December 31, 2011. The 10-K will be posted to the Company’s website at www.billbarrettcorp.com and found under “SEC Reports”.
UPCOMING EVENTS
Investor Conferences
Updated investor presentations will be posted to the homepage of the Company’s website at www.billbarrettcorp.com for each event below. Please check the website at 5:00 Mountain time on the business day prior to the investor event for the most recent presentation:
Chief Operating Officer Scot Woodall will participate in investor meetings at the 2012 Simmons Energy Conference on Friday, March 2, 2012. The event is not webcast.
Chairman, Chief Executive Officer and President Fred Barrett will participate in investor meetings at the 3rd Annual Wells Fargo Securities Exploration and Production Forum on Tuesday, March 13, 2012. The event is not webcast.
Chairman, Chief Executive Officer and President Fred Barrett will present at the Howard Weil 2012 Energy Conference on Monday, March 26, 2012 at 3:55 p.m. Central time. The event is not webcast.
DISCLOSURE STATEMENTS
Calculation of Natural Gas Liquids as a Percent of Sales Volumes
The Company’s natural gas production is based on wellhead volumes and its natural gas revenue includes the incremental revenue benefit of receiving NGL sales prices for NGL volumes processed by the purchasers of our natural gas deliveries. Many oil and gas producing companies report NGL volumes and revenues separately from natural gas volumes and revenues. In order to provide a metric that is comparable to other oil and gas production companies, the Company is providing the percentage of total company sales volumes that receive NGL pricing based on the barrel of oil equivalent NGL volumes for revenues received from our gas purchasers or processors. The NGL volumes identified by our gas purchasers or processors are converted to an oil equivalent based on 42 gallons per barrel and compared to overall gas equivalent production based on a 1 barrel to 6 Mcf ratio.
Reserve Disclosure
The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. The Company does not plan to include probable and possible reserve estimates in its filings with the SEC.
The Company has provided internally generated estimates for probable and possible reserves in this release. The estimates conform to SEC guidelines. They are not prepared or reviewed by third party engineers. Our probable and possible reserve estimates are determined using strip pricing, which we use internally for planning and budgeting purposes. The Company’s estimate of probable and possible reserves is provided in this release because management believes it is useful, additional information that is widely used by the investment community in the valuation, comparison and analysis of companies. U.S. investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2011, available on the Company’s website at www.billbarrettcorp.com or from the corporate offices at 1099 18th Street, Suite 2300, Denver, CO 80202. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or at www.sec.gov.
Forward-Looking Statements
This press release contains forward-looking statements, including statements regarding projected results and future events. In particular, the Company is providing “2012 Guidance,” which contains projections for certain 2012 operational and financial results. These forward-looking statements are based on management’s judgment as of this date and include certain risks and uncertainties. Please refer to the Company’s Annual Report on Form 10-K for the year-ended December 31, 2011 filed with the SEC, and other filings including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, for a list of certain risk factors that may affect these forward-looking statements.
Actual results may differ materially from Company projections and can be affected by a variety of factors outside the control of the Company including, among other things, market conditions, oil and gas price volatility, exploration and development drilling and testing results, performance of acquired properties, the ability to receive drilling and other permits and rights-of-way, regulatory approvals, governmental laws and regulations and changes in enforcement of those laws and regulations, new laws and regulations, risks related to and costs of hedging activities including counterparty viability, surface access and costs, availability of third party gathering, transportation, processing and refining, the availability and cost of services and materials, the ability to obtain industry partners to jointly explore certain prospects and the willingness and ability of those partners to meet capital obligations when requested, availability and costs of financing to fund the Company’s operations, uncertainties inherent in oil and gas production operations and estimating reserves, the speculative actual recovery of estimated potential volumes, unexpected future capital expenditures, competition, risks associated with operating in one major geographic area, the success of the Company’s risk management activities, title to properties, litigation, environmental liabilities, and other factors discussed in the Company’s reports filed with the SEC. Bill Barrett Corporation encourages readers to consider the risks and uncertainties associated with projections and other forward-looking statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances.
ABOUT BILL BARRETT CORPORATION
Bill Barrett Corporation (NYSE: BBG), headquartered in Denver, Colorado, explores for and develops natural gas and oil in the Rocky Mountain region of the United States. Additional information about the Company may be found on its website www.billbarrettcorp.com.
BILL BARRETT CORPORATION
Selected Operating Highlights
(Unaudited)
Three Months Twelve Months
Ended Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
Production Data:
----------------
Natural gas (MMcf) 26,260 22,459 97,856 89,964
Oil (MBbls) 466 294 1,490 1,089
Combined volumes
(MMcfe) 29,056 24,223 106,796 96,498
Daily combined
volumes (Mmcfe/d) 316 263 293 264
------------------ --- --- --- ---
Average Prices
(before the effects
of realized
hedges):
--------------------
Natural gas (per
Mcf) $5.44 $5.06 $5.71 $5.26
Oil (per Bbl) 81.57 71.97 81.97 67.93
Combined (per Mcfe) 6.23 5.56 6.37 5.67
------------------- ---- ---- ---- ----
Average Realized
Prices (after the
effects of realized
hedges):
--------------------
Natural gas (per
Mcf) $6.26 $6.47 $6.46 $6.74
Oil (per Bbl) 81.48 71.05 80.63 69.91
Combined (per Mcfe) 6.96 6.86 7.05 7.07
------------------- ---- ---- ---- ----
Average Costs (per
Mcfe):
------------------
Lease operating
expense $0.54 $0.54 $0.53 $0.54
Gathering,
transportation and
processing expense 0.94 0.72 0.87 0.72
Production tax
expense (1) 0.28 0.30 0.35 0.34
Depreciation,
depletion and
amortization 2.68 2.84 2.70 2.70
General and
administrative
expense,
excluding non-
cash stock-
based
compensation (2) 0.39 0.43 0.45 0.42
(1) Production tax expense for the twelve months
ended December 31, 2010 includes a one-time benefit
to reduce and re-estimate prior periods as a result
of amended returns filed with the State of Utah
regarding the calculation of severance taxes.
Exclusive of the one-time benefits, the production
tax expense per Mcfe for the twelve months of 2010
would have been $0.36.
(2) Management believes the separate presentation of
the non-cash component of general and administrative
expense is useful because the cash portion provides a
better understanding of cash required for general and
administrative expenses. Management also believes
that this disclosure may allow for a more accurate
comparison to the Company's peers that may have
higher or lower costs associated with equity grants.
BILL BARRETT CORPORATION
Consolidated Statements of Operations
(Unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
(in thousands,
except per
share
amounts)
Operating
and
Other
Revenues:
---------
Oil and gas
production (1) $207,615 $173,496 $780,751 $708,452
Commodity
derivative
(loss) (1) (1,529) (7,657) (14,263) (10,579)
Other 845 (2,441) 4,873 591
----- --- ------ ----- ---
Total
operating
and other
revenues 206,931 163,398 771,361 698,464
---------- ------- ------- ------- -------
Operating
Expenses:
---------
Lease
operating 15,546 13,017 56,603 52,040
Gathering,
transportation
and
processing 27,318 17,331 93,423 69,089
Production
tax (2) 8,205 7,214 37,498 32,738
Exploration 1,043 4,325 3,645 9,121
Impairment,
dry hole
costs and
abandonment 99,036 36,144 117,599 44,664
Depreciation,
depletion
and
amortization 78,015 69,039 288,421 260,665
General and
administrative (3) 11,195 10,324 47,744 40,884
Non-cash
stock-
based
compensation (3) 5,337 5,739 19,036 16,908
------------- --- ----- ----- ------ ------
Total
operating
expenses 245,695 163,133 663,969 526,109
---------- ------- ------- ------- -------
Operating
Income/
(loss) (38,764) 265 107,392 172,355
--------- ------- --- ------- -------
Other
Income
and
Expense:
---------
Interest
income and
other
income
(expense) (560) 46 (397) 402
Interest
expense (20,238) (11,810) (58,616) (44,302)
-------- ------- ------- ------- -------
Total other
income and
expense (20,798) (11,764) (59,013) (43,900)
----------- ------- ------- ------- -------
Income
before
Income
Taxes (59,562) (11,499) 48,379 128,455
Provision
for
Income
Taxes (21,782) (4,264) 17,672 47,953
--------- ------- ------ ------ ------
Net
Income/
(loss) $(37,780) $(7,235) $30,707 $80,502
-------- -------- ------- ------- -------
Net
Income
Per
Common
Share
Basic $(0.81) $(0.16) $0.66 $1.78
Diluted $(0.81) $(0.16) $0.65 $1.75
------- ------ ------ ----- -----
Weighted Average Common Shares
Outstanding
Basic 46,888 45,666 46,536 45,218
Diluted 46,888 45,666 47,237 45,887
------- ------ ------ ------ ------
(1) The table below summarizes the realized and unrealized gains and losses
the Company recognized related to its oil and natural gas derivative
instruments for the periods indicated:
Three Months Ended Twelve Months Ended
December 31, December 31,
------------------- --------------------
2011 2010 2011 2010
---- ---- ---- ----
Included in oil and gas
production revenue:
Realized gain on cash
flow hedges $26,699 $38,757 $99,922 $161,496
======= ======= ========
Included in commodity derivative
gain (loss):
Realized loss on
derivatives not
designated as cash flow
hedges $(5,349) $(7,239) $(28,054) $(26,166)
Unrealized
ineffectiveness gain
(loss) recognized on
derivatives designated
as cash flow hedges (6) (1,209) 1,026 (2,256)
Unrealized gain on
derivatives not
designated as cash flow
hedges 3,826 791 12,765 17,843
----- --- ------ ------
Total commodity
derivative gain (loss) $(1,529) $(7,657) $(14,263) $(10,579)
======= ======= ======== ========
(2) Production tax expense for the twelve months ended December 31, 2010
includes a one-time benefit to reduce and re-estimate prior periods as a
result of amended returns filed with the State of Utah regarding the
calculation of severance taxes.
(3) Management believes the separate presentation of the non-cash component
of general and administrative expense is useful because the cash portion
provides a better understanding of cash required for general and
administrative expenses. Management also believes that this disclosure may
allow for a more accurate comparison to the Company's peers that may have
higher or lower costs associated with equity grants.
BILL BARRETT CORPORATION
Consolidated Condensed Balance Sheets
(Unaudited)
As of As of
December 31,
2011 December 31, 2010
(in thousands)
Assets:
-------
Cash and cash equivalents $57,331 $58,690
Other current assets (1) 189,012 148,958
Property and equipment,
net 2,406,764 1,811,819
Other noncurrent assets 34,823 19,033
----------------------- ------ ------
Total assets $2,687,930 $2,038,500
------------ ---------- ----------
Liabilities and Stockholders'
Equity:
-----------------------------
Current liabilities (1) $233,198 $165,957
Notes payable to bank 70,000 -
Senior notes 641,198 239,766
Convertible senior
notes 171,042 164,633
Other long-term
liabilities (1) 353,654 327,182
Stockholders' equity 1,218,838 1,140,962
-------------------- --------- ---------
Total liabilities and
stockholders' equity $2,687,930 $2,038,500
---------------------- ---------- ----------
(1) At December 31, 2011, the estimated fair value of all of our
commodity derivative instruments was a net asset of $83.3 million,
comprised of: $77.3 million current assets; ($2.5) million current
liabilities; $8.9 million non-current assets; and ($0.4) million non-
current liabilities. This amount will fluctuate quarterly based on
estimated future commodity prices and the current hedge position.
BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
(in thousands)
Operating Activities:
---------------------
Net income $(37,780) $(7,235) $30,707 $80,502
Adjustments to reconcile to
net cash
provided by operations:
Depreciation, depletion and
amortization 78,015 69,039 288,421 260,665
Impairment, dry hole costs and
abandonment expense 99,036 36,144 117,599 44,664
Unrealized derivative
(gain)\loss (3,820) 418 (13,791) (15,587)
Deferred income taxes (21,782) (2,989) 17,688 57,361
Stock compensation and other
non-cash charges 5,995 6,779 21,953 19,032
Amortization of debt discounts
and deferred financing costs 4,037 3,200 13,886 12,031
Loss (gain) on sale of
properties 54 193 (1,955) (806)
---------------------- --- --- ------ ----
Change in assets and
liabilities:
Accounts receivable (12,901) (9,941) (27,680) (10,021)
Prepayments and other assets (808) 3,364 1,809 (6,939)
Accounts payable, accrued and
other liabilities 36,683 12,755 24,531 2,812
Amounts payable to oil & gas
property owners (11,771) (5,798) (4,010) (352)
Production taxes payable 417 704 10,190 3,826
------------------------ --- --- ------ -----
Net cash provided by operating
activities $135,375 $106,633 $479,348 $447,188
------------------------------ -------- -------- -------- --------
Investing Activities:
---------------------
Additions to oil and gas
properties, including
acquisitions (245,809) (131,390) (947,206) (444,871)
Additions of furniture,
equipment and other (5,384) (2,016) (11,142) (4,107)
Proceeds from sale of
properties and other
investing activities (102) 528 1,702 2,661
--------------------- ---- --- ----- -----
Net cash used in investing
activities $(251,295) $(132,878) $(956,646) $(446,317)
-------------------------- --------- --------- --------- ---------
Financing Activities:
---------------------
Proceeds from debt 70,000 - 800,000 20,000
Principal payments on debt - - (330,000) (25,000)
Deferred financing costs and
other (5,224) (36) (16,308) (15,293)
Proceeds from stock option
exercises 3,256 13,199 22,247 23,707
-------------------------- ----- ------ ------ ------
Net cash provided by financing
activities $68,032 $13,163 $475,939 $3,414
------------------------------ ------- ------- -------- ------
Increase/(Decrease) in Cash
and Cash Equivalents (47,888) (13,082) (1,359) 4,285
Beginning Cash and Cash
Equivalents 105,219 71,772 58,690 54,405
----------------------- ------- ------ ------ ------
Ending Cash and Cash
Equivalents $57,331 $58,690 $57,331 $58,690
-------------------- ------- ------- ------- -------
BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow & Adjusted Net Income
(Unaudited)
Discretionary Cash Flow Reconciliation
Three Months Ended Twelve Months Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
(in thousands, except per share amounts)
Net Income/(loss) $(37,780) $(7,235) $30,707 $80,502
Adjustments to reconcile to discretionary cash
flow:
Depreciation, depletion and amortization 78,015 69,039 288,421 260,665
Impairment, dry hole and abandonment expense 99,036 36,144 117,599 44,664
Exploration expense 1,043 4,325 3,645 9,121
Unrealized derivative (gain)/loss (3,820) 418 (13,791) (15,587)
Deferred income taxes (21,782) (2,989) 17,688 57,361
Stock compensation and other non-cash charges 5,995 6,779 21,953 19,032
Amortization of debt discounts and deferred
financing costs 4,037 3,200 13,886 12,031
Loss (gain) on sale of properties 54 193 (1,955) (806)
--------------------------------- --- --- ------ ----
Discretionary Cash Flow $124,798 $109,874 $478,153 $466,983
----------------------- -------- -------- -------- --------
Per share, diluted $2.66 $2.41 $10.12 $10.18
Per Mcfe $4.30 $4.54 $4.48 $4.84
Adjusted Net Income Reconciliation
Three Months Ended Twelve Months Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
(in thousands except per share amounts)
Net Income/(loss) $(37,780) $(7,235) $30,707 $80,502
Adjustments to net income:
Unrealized derivative (gain)/loss (3,820) 418 (13,791) (15,587)
Impairment expense 96,399 15,616 100,278 15,616
Loss (gain) on sale of properties 54 193 (1,955) (806)
One time items:
Production
tax expense - - - (2,184)
----------- --- --- --- ------
Subtotal Adjustments 92,633 16,227 84,532 (2,961)
Effective tax rate 37% 37% 37% 37%
------------------ --- --- --- ---
Tax effected adjustments 58,359 10,223 53,255 (1,865)
------------------------ ------ ------ ------ ------
Adjusted Net Income $20,579 $2,988 $83,962 $78,637
------------------- ------- ------ ------- -------
Per share, diluted $0.44 $0.07 $1.78 $1.71
Per Mcfe $0.71 $0.12 $0.79 $0.81
The non-GAAP (Generally Accepted Accounting Principles in the United States of America) measures of
discretionary cash flow and adjusted net income are presented because management believes that they provide
useful additional information to investors for analysis of the Company's ability to internally generate
funds for exploration, development and acquisitions as well as adjusting net income for unusual items to
allow for a more consistent comparison from period to period. In addition, these measures are widely used by
professional research analysts and others in the valuation, comparison and investment recommendations of
companies in the oil and gas exploration and production industry, and many investors use the published
research of industry research analysts in making investment decisions.
These measures should not be considered in isolation or as a substitute for net income, income from
operations, net cash provided by operating activities or other income, profitability, cash flow or liquidity
measures prepared in accordance with GAAP. Because discretionary cash flow and adjusted net income exclude
some, but not all, items that affect net income and net cash provided by operating activities and may vary
among companies, the amounts presented may not be comparable to similarly titled measures of other
companies.
BILL BARRETT CORPORATION
Costs Incurred and Reserve Information
(Unaudited)
2011 2010 2009
---- ---- ----
($ in millions)
TOTAL CAPITAL
EXPENDITURES $987.3 $473.3 $406.4
Furniture, fixtures
and equipment and
real estate (10.6) (3.8) (3.7)
Asset retirement
obligation 12.1 1.3 (1.2)
---------------- ---- --- ----
TOTAL COSTS INCURRED
(1) $988.8 $470.8 $401.5
-------------------- ------ ------ ------
TOTAL COSTS INCURRED
DISCLOSURE
Exploration costs 20.8 $82.8 $185.4
Development costs 607.7 358.3 147.2
Acquisition costs:
Unproved properties 183.4 25.2 70.1
Proved properties 164.8 3.2 -
Asset retirement
obligation 12.1 1.3 (1.2)
---------------- ---- --- ----
TOTAL COSTS INCURRED 988.8 470.8 401.5
less: Asset
retirement
obligation (12.1) (1.3) 1.2
less:
(Proceeds)/adjusted
proceeds received
from JV partners - 1.5 -
less: Capitalized
interest (1.4) (4.2) (4.6)
----------------- ---- ---- ----
Adjusted costs
incurred (1) $975.3 $466.8 $398.1
-------------- ------ ------ ------
RESERVE ADDITIONS
(Bcfe)
Extensions,
discoveries and
other additions 211.4 185.1 177.3
Revisions of
previous estimates
based on
performance 37.9 39.8 101.5
Revisions of
previous estimates
based on price 5.5 27.4 (42.8)
Purchases of
reserves in place 98.3 1.4 0.5
------------------ ---- --- ---
RESERVE ADDITIONS
Bcfe 353.1 253.7 236.5
----------------- ----- ----- -----
RESERVE ADDITIONS
MMBoe 58.9 42.3 39.4
----------------- ---- ---- ----
SALES INFORMATION
-----------------
Property sales $2.0 $4.4 $3.7
Sales of reserves
(Bcfe) - 3.7 0.2
----------------- --- --- ---
(1) Finding and developments cost is a non-GAAP metric
commonly used in the exploration and production industry. The
calculation presented by the Company of $16.57 per Boe for
2011, or $13.09 per Boe for the three-year average, is the
quotient of "Adjusted costs incurred" divided by "Reserve
additions." The calculation may not be comparable to similarly
titled measures provided by other companies.
SOURCE Bill Barrett Corporation
