Exhibit 99.1
 | Press Release |
For immediate release
Company contact: Jennifer Martin, Vice President of Investor Relations, 303-312-8155
Bill Barrett Corporation Reports Second Quarter 2013 Results,
Multiple Strong Well Results from DJ Basin & Powder River Basin Deep Oil Programs
DENVER – August 1, 2013 – Bill Barrett Corporation (NYSE: BBG) today reported second quarter 2013 results and announced operational updates highlighted by:
| • | Oil, natural gas and natural gas liquids (“NGL”) production of 21.4 Bcfe |
| • | Oil production averaging 9,060 barrels per day, or 23% of production |
| • | Average realized price of $6.56 per Mcfe, reflecting the benefit of growing oil volumes. Oil sales accounted for 47% of pre-hedge sales revenues |
| • | Discretionary cash flow of $65.7 million, or $1.38 per diluted common share |
| • | Bigger wells in the Northeast Wattenberg. Three new Niobrara ‘B’ wells in the Denver-Julesburg Basin (“DJ”) averaged approximately 1,000 barrels of oil equivalent per day (“Boe/d”) peak 24-hour initial production (“IP”) rate and 517 Boe/d over 30-days, demonstrating increased rates with new completion and artificial lift technology |
| • | More success in the Powder Deep Oil Program. Five new wells averaged 816 Boe/d peak 24-hour IP rate and 516 Boe/d over 30-days, while wells are temporarily restricted awaiting tie-in to natural gas facilities |
Chief Executive Officer and President Scot Woodall commented: “We are encouraged with our strong and improving well results in the Northeast Wattenberg. Our most recent wells, in which we applied larger fracture stimulations and timely installed gas lift, are performing well. We are now increasing our rig count to four rigs and plan by year-end to delineate our 40,000 acre position, test 80-acre spacing in the Niobrara ‘B’, and drill the Niobrara ‘C’, Codell, and one extended reach lateral. We are excited about the upside potential of this area, and we are focused on realizing the associated value.
“Through the remainder of 2013, our operations focus will be redirected to the Northeast Wattenberg, with the planned Uinta Oil drilling program nearly completed for the year. Four rigs will be active in the Northeast Wattenberg later this month, slightly delayed from original expectations. As a result, our capital expenditure guidance for 2013 is reduced by $25 million at the mid-point. In conjunction with the timing of well completions in the Northeast Wattenberg as well as performance of certain wells in the Uinta Oil Program, we are also reducing our production forecast for 2013 by 4% at the mid-point. Of note, the production impact in the Uinta Oil Program stems from various causes, including testing new completion concepts in the area that did not meet expectations. The number of future drilling locations in the area is not affected, and the area continues to be a major oil resource. We remain committed to capital discipline and completing an asset divestiture as part of our portfolio management program. This activity is well underway, and we are confident that we are on track to complete a transaction by year-end.
“We expect the second half of 2013 to deliver positive, quantifiable results in the Northeast Wattenberg, completion of an asset divestiture and oil production exit rate of approximately 12 thousand barrels per day (“MBbls/d”), positioning our Company for solid year-end oil reserve growth and 2014 cash flow.”
OPERATING AND FINANCIAL RESULTS
Oil, natural gas and NGL production totaled 21.4 billion cubic feet equivalent (“Bcfe”) in the second quarter of 2013, based on three-stream reporting adopted as of January 1, 2013. (Second quarter of 2013 production on a comparable two-stream basis would have been 20.5 Bcfe.) Production is down from 29.9 Bcfe reported in the second quarter of 2012 (reported on a two- stream basis) primarily due to asset sales closed in the fourth quarter of 2012 and up slightly from 21.2 Bcfe reported in the first quarter of 2013. Oil production of 9,060 Bbls/d in the second quarter of 2013 was up 30% compared with the second quarter of 2012, including a 40% increase at the Uinta Oil Program and a 55% increase in the DJ Basin, partially offset by the oil production (condensate) sold in the fourth quarter of 2012 asset sale.
Realized pricing in the second quarter of 2013 was $6.56 per thousand cubic feet equivalent (“Mcfe”), up 10% from the second quarter of 2012, reflecting the significant growth in oil volumes year-over-year and benefited by $0.08 per Mcfe from realized hedges. The average realized prices by commodity for the second quarter of 2013 were $82.11 per barrel (“Bbl”) of oil, $3.92 per Mcfe of natural gas and $46.38 per Bbl of NGLs (reflecting the Company’s election to reject ethane on the majority of its NGLs during the second quarter.) (See “Selected Operating Highlights” below for more detail.)
The table below presents production volumes, sales volumes (see “Disclosure Statements” below) and realized prices historically by quarter. 2013 production reflects the effects of the 2012 asset sale, the change to three-stream reporting and the Company’s election to reject ethane in the Piceance Basin:
| 2Q12 | 3Q12 | 4Q12 | 1Q13 | 2Q13 | ||||||||||||||||
Reported Production Volumes 3-Stream: | ||||||||||||||||||||
Oil (Bbls/d) | N/A | N/A | N/A | 8,827 | 9,060 | |||||||||||||||
Natural gas (MMcf/d) | N/A | N/A | N/A | 163 | 157 | |||||||||||||||
NGLs ethane rejected (Bbls/d) | N/A | N/A | N/A | 3,349 | 3,854 | |||||||||||||||
Reported Production Volumes 2-Stream: | ||||||||||||||||||||
Oil (Bbls/d) | 6,972 | 7,766 | 9,315 | N/A | N/A | |||||||||||||||
Natural gas, including NGLs (MMcf/d) | 287 | 294 | 251 | N/A | N/A | |||||||||||||||
Sales* Volumes: | ||||||||||||||||||||
Oil (Bbls/d) | 6,972 | 7,766 | 9,315 | 8,827 | 9,060 | |||||||||||||||
Natural gas sold as dry gas (MMcf/d) | 262 | 265 | 223 | N/A | N/A | |||||||||||||||
NGLs (Bbls/d) | 11,439 | 10,341 | 8,687 | N/A | N/A | |||||||||||||||
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Reported Realized Prices | ||||||||||||||||||||
Oil (per Bbl) | $ | 84.86 | $ | 84.08 | $ | 83.84 | $ | 81.74 | $ | 82.11 | ||||||||||
Natural gas sold as dry gas (per Mcf) | N/A | N/A | N/A | $ | 4.10 | $ | 3.92 | |||||||||||||
Natural gas including benefit of NGL realizations (per Mcf) | $ | 4.77 | $ | 4.90 | $ | 5.18 | N/A | N/A | ||||||||||||
NGLs (per Bbl) | N/A | N/A | N/A | $ | 48.32 | $ | 46.38 | |||||||||||||
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| * | (see “Disclosure Statements” below) |
Discretionary cash flow (a non-GAAP measure, see “Discretionary Cash Flow Reconciliation” below) in the second quarter of 2013 was $65.7 million, or $1.38 per diluted common share, down from $94.7 million in the second quarter of 2012. The decline in discretionary cash flow in the
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second quarter of 2013 compared with the second quarter of 2012 was primarily due to lower production (described above). Cash operating costs (lease operating expense, gathering transportation and processing expense and production tax expense) per unit were higher in the second quarter of 2013 at $2.00 compared with the second quarter of 2012 at $1.73. Higher costs were partially offset by higher realized prices, per Mcfe. For the first six months of 2013, discretionary cash flow was $129.4 million compared with $193.6 million for the first six months of 2012.
Net income in the second quarter of 2013 was $14.3 million, or $0.30 per diluted common share, compared with net income of $3.3 million in the second quarter of 2012. Net income in the quarter was affected by the same items that affected discretionary cash flow (described above) and higher per unit depreciation and depletion expense. Lower net income in the prior year quarter was negatively affected by impairment and exploration charges. Adjusted net income for the second quarter of 2013 (a non-GAAP measure, see “Adjusted Net Income Reconciliation” below) was a loss of $9.1 million, or ($0.19) per diluted common share, compared with a loss of $2.4 million, or ($0.05) per diluted common share, in the second quarter of 2012. Adjusted net income (loss) removes the effect of non-recurring charges such as unrealized derivative gains and losses, impairment expenses, property sales and certain one-time items. For the first six months of 2013, adjusted net income was a loss of $21.3 million compared with income of $7.3 million for the first six months of 2012.
DEBT AND LIQUIDITY
At June 30, 2013, the Company had total debt outstanding (principal balance) of $1,248.4 million including $80.0 million drawn on its $825.0 million revolving credit facility due 2016. Subsequent to June 30, 2013, the Company redeemed its $250.0 million 9.875% Senior Notes and funded the redemption with borrowings under the revolving credit facility, substantially reducing the interest rate on this debt. Pro forma for this transaction (including the redemption premium) and after deducting an outstanding letter of credit for $26.0 million, borrowing capacity on the Company’s revolving credit facility at quarter-end was $456.7 million, and the Company has no term debt due before 2019.
OPERATIONS
Production, Wells Spud and Capital Expenditures
The following table lists production, wells spud and total capital expenditures by basin for the three and six months ended June 30, 2013:
| Three Months Ended June 30, 2013 | Six Months Ended June 30, 2013 | |||||||||||||||||||||||
Average MMcfe | Wells Spud Gross* | Capital Expenditures $mm | Average MMcfe | Wells Spud Gross* | Capital Expenditures $mm | |||||||||||||||||||
Basin | ||||||||||||||||||||||||
Uinta: | ||||||||||||||||||||||||
Uinta Oil Program | 40 | 27 | $ | 67 | 41 | 48 | $ | 132 | ||||||||||||||||
West Tavaputs | 68 | 0 | 2 | 70 | 0 | 3 | ||||||||||||||||||
Piceance | 99 | 0 | 2 | 100 | 0 | 4 | ||||||||||||||||||
Denver-Julesberg | 18 | 11 | 36 | 17 | 13 | 56 | ||||||||||||||||||
Powder River Deep Oil & Other | 10 | 1 | 12 | 7 | 5 | 42 | ||||||||||||||||||
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Total | 235 | 39 | $ | 119 | 235 | 66 | $ | 237 | ||||||||||||||||
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| * | Operated wells |
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Operating and Drilling Update
The Company anticipates drilling or participating in approximately 180 gross/100 net development wells in 2013, including participation in approximately 40 gross non-operated wells. The Company’s development program will focus on growth in oil production and reserves at its established development programs.
Denver-Julesburg Basin, Colorado and Wyoming
Northeast Wattenberg/DJ Basin – Second quarter net production averaged nearly 3,000 Boe/d. Today, the Company is providing results on three new wells, all of which demonstrate higher rates as a result of improvement in completion technology and changes in artificial lift. The three wells, drilled in the northern portion of the position, had an average 24-hour peak IP rate of approximately 1,000 Boe/d and an average 30-day rate of 517 Boe/d. The three wells were drilled to approximately 6,300 feet vertical depth with approximate 4,000 foot laterals and were completed with 17 fracture stimulation stages. The Company continues to refine drilling and completion technology and drive cost optimizations in the area.
The Company will have four active rigs in the area by month-end to complete a full year program that includes drilling approximately 65 gross/42 net operated wells, of which approximately 50 gross operated wells should be completed by year-end. The Company also anticipates participating in approximately 25 non-operated wells. The 2013 drilling program will focus on realizing value through development and delineation drilling on the Company’s approximate 40,000 net acre Northeast Wattenberg position, which lies in the middle of industry activity in the area.
At June 30, 2013, the Company had an approximate 76% working interest in production from 275 gross wells, including approximately 200 vertical wells mostly acquired in DJ Basin property acquisitions.
Uinta Basin, Utah
Uinta Oil Program (Blacktail Ridge, Lake Canyon, East Bluebell and South Altamont) – Second quarter net production averaged 6,740 Boe/d. The Company plans to operate one-to-two rigs in the area for the remainder of the year to complete its planned full year program that includes approximately 65 gross/40 net operated wells.
Current year production from the area is expected to be lower than original plan primarily due to two causes. The Company applied various completion techniques aimed at improving overall returns that did not meet expectations, and performance of certain wells drilled late 2012 early 2013 statistically underperformed the type curve. While these results affect production for 2013, they do not adversely affect the drilling location inventory count.
Through the remainder of the year, the Company will continue its 2013 program with one-to-two rigs in the East Bluebell/South Altamont areas where well results are delivering strong returns. The Company continues to optimize drilling and operating costs in this sizable program and is currently testing a vertical 80-acre spacing pilot program in the Blacktail-Ridge area where preliminary results to date have been encouraging.
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At June 30, 2013, the Company had an approximate 70% working interest in production from 272 gross wells. Depending upon elections to participate by partners, the Company may have a lower working interest in its 2013 drilling program. As of the end of the second quarter of 2013, the Company had approximately 151,650 net acres (including acreage to be earned) in the program.
West Tavaputs – Second quarter net production averaged 68 million cubic feet equivalent per day (MMcfe/d). Drilling in the area remains suspended as the Company focuses its operations plan on oil development. The Company has retained an advisor to market this asset for possible sale.
At June 30, 2013, the Company had an approximate 97% working interest in production from 302 gross wells.
Piceance Basin, Colorado
Gibson Gulch – Second quarter net production averaged 99 MMcfe/d. Drilling in the area remains suspended as the Company focuses its operations plan on oil development.
At June 30, 2013, the Company had an approximate 81% working interest in production from 955 gross wells in its Gibson Gulch program.
Powder River Basin, Wyoming
Powder Deep Oil Program – Second quarter net production averaged approximately 1,500 Boe/d. The Company holds a 68,120 net acre position in the Powder River Basin, a stacked oil play. The Company has drilled successful wells targeting the Sussex, Shannon and Frontier formations. Other operators have drilled successful wells on, or near, the Company’s acreage which are productive in the Turner and Parkman formations.
Today, the Company is providing very positive results on its operated 5-well 2013 program, which was completed in the first half of 2013. The five wells had 24-hour peak IP rates averaging 816 Boe/d and 30-day rates averaging 516 Boe/d. Flow rates are restricted awaiting tie-in to regional natural gas infrastructure. All of the wells in the 2013 program were drilled to the Shannon formation between 8,500-8,800 feet vertical depth with 3,800-4,400 foot laterals and 17-18 fracture stimulation stages. These wells follow four strong wells completed in 2012 to the Shannon, Sussex and Frontier formations. The Company plans to participate in a number of non-operated wells through the remainder of the year. The Company believes the Powder River Deep Oil Program offers a new, growing oil position in a relatively low risk basin, yet it is also considering this asset for possible sale.
At June 30, 2013, the Company had an approximate 42% working interest in production from 95 gross wells.
ADDITIONAL FINANCIAL INFORMATION
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.
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For 2013 and 2014, the Company has hedges in place as outlined in the table below. Swap positions for natural gas and NGLs are tied to regional sales points and oil hedge positions are tied to WTI and include:
| • | For the second half of 2013, 30.9 Bcfe, or approximately 70% of production, at a weighted average price of $7.97 per Mcfe. Approximately 75% of natural gas and oil production and 20% of NGL production/sales is hedged. |
| • | For 2014, approximately 43.4 Bcfe at a weighted average blended price of $8.41 per Mcfe. |
The following table summarizes hedge positions as of July 19, 2013:
| Natural Gas | NGLs* | Oil | ||||||||||
| Period | Volume MMBtu/d | Price $/MMBtu | Volume Bbls/d | Price $/Bbl | Volume Bbls/d | Price $/Bbl | ||||||
3Q13 | 125.0 | 3.73 | 873 | 74.74 | 8,300 | 97.62 | ||||||
4Q13 | 123.4 | 3.72 | 873 | 74.74 | 8,300 | 97.62 | ||||||
1Q14 | 85.0 | 3.87 | — | — | 8,400 | 94.06 | ||||||
2Q14 | 85.0 | 3.87 | — | — | 8,400 | 94.06 | ||||||
3Q14 | 85.0 | 3.87 | — | — | 6,000 | 94.46 | ||||||
4Q14 | 78.4 | 3.85 | — | — | 6,000 | 94.46 | ||||||
| * | NGL volumes include propane, butanes and natural gasoline. No ethane volumes are hedged. |
2013 Guidance
The Company’s updated 2013 guidance (please reference “Forward-Looking Statements” below) is as follows. The Company may update guidance as business conditions warrant:
| • | Capital expenditures of $465 million to $485 million, narrowed and lowered by $25 million at the mid-point. |
| • | Oil, natural gas and NGL production of 83 to 86 Bcfe, narrowed and lowered at the mid-point from 88 Bcfe. Oil production is expected to increase approximately 30% to 35% in 2013 over 2012, lowered from 50%+ growth. |
| • | Lease operating costs of $64 million to $67 million, narrowed from $62 million to $67 million and inclusive of one-time charges of $1.2 million associated with the West Tavaputs compressor fire. |
| • | Gathering, transportation and processing costs of $65 million to $68 million, unchanged. |
| • | General and administrative expenses before non-cash stock-based compensation cost of $50 million to 54 million, unchanged. |
SECOND QUARTER 2013 RESULTS WEBCAST AND CONFERENCE CALL
As previously announced, a webcast and conference call will be held tomorrow morning to discuss second quarter 2013 results. Please join Bill Barrett Corporation executive management at 11:00 a.m. Eastern time/9:00 a.m. Mountain time on August 2, 2013 for the live webcast, accessed atwww.billbarrettcorp.com, or join by telephone by calling 866-515-2915 (617-399-5129 international callers) with passcode 74510286. The webcast will remain available on the Company’s website for approximately 30 days, and a replay of the call will be available through August 9, 2013 at call-in number 888-286-8010 (617-801-6888 international) with passcode 45058698. The Company also has tentatively scheduled its third quarter 2013 earnings conference call for November 1, 2013, typically at 11:00 a.m. Eastern time/9:00 a.m. Mountain time.
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QUARTERLY REPORT ON FORM 10-Q
The Company plans to file tomorrow its Quarterly Report on Form 10-Q for the quarter ended June 30, 2013. The Form 10-Q will be posted to the Company’s website atwww.billbarrettcorp.com and found under “SEC Filings”.
UPCOMING EVENTS
Updated investor presentations will be posted to the homepage of the Company’s website atwww.billbarrettcorp.com for each event below.Webcast events will also be accessible on the homepage of the Company’s website:
Investor Conferences
Chief Executive Officer and President Scot Woodall will present at Enercom’s The Oil & Gas Conference at 1:20 p.m. Eastern time (11:20 a.m. Mountain time) on Wednesday, August 14, 2013. The event will be webcast. The live and archived webcast will be accessible on the Company’s homepage atwww.billbarrettcorp.com. The Company will post an investor presentation to the homepage of its website at 5:00 p.m. Mountain time on Monday, August 12, 2013.
Chief Executive Officer and President Scot Woodall will present at the Barclays 2013 CEO Energy-Power Conference at 9:05 a.m. Eastern time on Thursday, September 12, 2013. The event will be webcast. The live and archived webcast will be accessible on the Company’s homepage atwww.billbarrettcorp.com. The Company will post an investor presentation to the homepage of its website at 5:00 p.m. Mountain time on Tuesday, September 10, 2013.
DISCLOSURE STATEMENTS
Natural Gas Liquids
Effective January 1, 2013, the Company began reporting its production volumes on a three-stream basis, which separately reports NGLs extracted from the natural gas stream and sold as a separate product. The NGL volumes identified by our gas purchasers 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.
Calculation of Natural Gas Liquids as a Percent of Sales Volumes
Prior to January 1, 2013, the Company reported natural gas production based on wellhead volumes and its natural gas revenue included the incremental revenue benefit from third party purchasers and processors when the Company elected to receive NGL values from certain volumes of natural gas. In order to provide a metric that is comparable to three-stream reporting, the Company is providing the percentage of total Company sales volumes by product including oil, natural gas and NGL revenues received from our gas purchasers or processors for certain historical time periods. 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.
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Forward-Looking Statements
This press release contains forward-looking statements, including statements regarding projected results and future events. In particular, the Company is providing revised “2013 guidance”, which contains projections for certain 2013 operational and financial metrics. These forward-looking statements are based on management’s judgment as of the date of this press release and include certain risks and uncertainties. Please refer to the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 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 other forward-looking statements and can be affected by a variety of factors outside the control of the Company including, among other things: oil, NGL and natural gas price volatility; the ability to complete property sales or other transactions; the ability to receive drilling and other permits and rights-of-way in a timely manner; development drilling and testing results; the potential for production decline rates to be greater than expected; performance of acquired properties and newly drilled wells; costs and availability of third party facilities for gathering, processing, refining and transportation; regulatory approvals, including regulatory restrictions on federal lands; legislative or regulatory changes, including initiatives related to hydraulic fracturing; higher than expected costs and expenses, including the availability and cost of services and materials; unexpected future capital expenditures; economic and competitive conditions; 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; declines in the values of our oil and gas properties resulting in impairments; changes in estimates of proved reserves; compliance with environmental and other regulations; derivative and hedging activities; 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 oil and natural gas in the Rocky Mountain region of the United States. Additional information about the Company may be found on its websitewww.billbarrettcorp.com.
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BILL BARRETT CORPORATION
Selected Operating Highlights
(Unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Production Data: | ||||||||||||||||||
Natural gas (MMcf) | 14,314 | 26,094 | 28,976 | 51,412 | ||||||||||||||
Oil (MBbls) | 825 | 634 | 1,619 | 1,115 | ||||||||||||||
NGLs (MBbls) | 351 | N/A | 652 | N/A | ||||||||||||||
Combined volumes (MMcfe) | 21,370 | 29,898 | 42,602 | 58,102 | ||||||||||||||
Daily combined volumes (MMcfe/d) | 235 | 329 | 235 | 319 | ||||||||||||||
Average Prices (before the effects of realized hedges): | ||||||||||||||||||
Natural gas (per Mcf) | $ | 4.06 | $ | 3.40 | (1) | $ | 3.89 | $ | 3.83 | |||||||||
Oil (per Bbl) | (2) | 78.99 | 78.89 | 78.86 | 83.62 | |||||||||||||
NGLs (per Bbl) | 43.12 | N/A | 44.87 | N/A | ||||||||||||||
Combined (per Mcfe) | 6.48 | 4.64 | 6.33 | 5.00 | ||||||||||||||
Average Realized Prices (after the effects of realized hedges): | ||||||||||||||||||
Natural gas (per Mcf) | $ | 3.92 | $ | 4.77 | (1) | $ | 4.01 | $ | 5.11 | |||||||||
Oil (per Bbl) | (2) | 82.11 | 84.86 | 81.93 | 86.39 | |||||||||||||
NGLs (per Bbl) | 46.38 | N/A | 47.27 | N/A | ||||||||||||||
Combined (per Mcfe) | 6.56 | 5.97 | 6.57 | 6.18 | ||||||||||||||
Average Costs (per Mcfe): | ||||||||||||||||||
Lease operating expense | $ | 0.75 | $ | 0.64 | $ | 0.82 | $ | 0.65 | ||||||||||
Gathering, transportation and processing expense | (2) | 0.88 | 0.87 | 0.81 | 0.92 | |||||||||||||
Production tax expense | 0.36 | 0.23 | 0.32 | 0.23 | ||||||||||||||
Depreciation, depletion and amortization | 3.48 | 2.87 | 3.35 | 2.75 | ||||||||||||||
General and administrative expense, excluding non-cash stock-based compensation expense | (3) | 0.47 | 0.38 | 0.59 | 0.43 | |||||||||||||
| (1) | Natural gas average prices include the effect of NGL revenues for the 2012 period. |
| (2) | Oil average prices for the six months ended June 30, 2013 include an approximate $5.30 per Bbl transportation deduct related to certain production within the Uinta Oil Program. Similarly, the three month periods ended March 31, 2013 and June 30, 2013 included a $5.50 and $5.20 charge, respectively. These costs were previously included within gathering, transportation and processing expense. The effect on the average per unit oil price is approximately $2.00 per Bbl. |
| (3) | This separate presentation is a non-GAAP (Generally Accepted Accounting Principal) measure. 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, which may have higher or lower costs associated with stock-based grants. |
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BILL BARRETT CORPORATION
Consolidated Statements of Operations
(Unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||||
| (in thousands, except per share amounts) | ||||||||||||||||||
Operating and Other Revenues: | ||||||||||||||||||
Oil, gas and NGLs | (1) | $ | 140,380 | $ | 159,490 | $ | 274,785 | $ | 336,532 | |||||||||
Other | 1,919 | 862 | 5,791 | 2,996 | ||||||||||||||
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Total operating and other revenues | 142,299 | 160,352 | 280,576 | 339,528 | ||||||||||||||
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Operating Expenses: | ||||||||||||||||||
Lease operating | 16,112 | 19,030 | 34,858 | 37,668 | ||||||||||||||
Gathering, transportation and processing | 18,772 | 25,862 | 34,360 | 53,214 | ||||||||||||||
Production tax | 7,781 | 6,892 | 13,732 | 13,099 | ||||||||||||||
Exploration | 141 | 4,062 | 236 | 4,501 | ||||||||||||||
Impairment, dry hole costs and abandonment | 1,182 | 21,075 | 8,283 | 21,639 | ||||||||||||||
Depreciation, depletion and amortization | 74,307 | 85,942 | 142,745 | 160,025 | ||||||||||||||
General and administrative | (2) | 10,047 | 11,314 | 25,195 | 25,114 | |||||||||||||
Non-cash stock-based compensation | (2) | 3,226 | 3,722 | 8,660 | 8,362 | |||||||||||||
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Total operating expenses | 131,568 | 177,899 | 268,069 | 323,622 | ||||||||||||||
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Operating Income | 10,731 | (17,547 | ) | 12,507 | 15,906 | |||||||||||||
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Other Income and Expense: | ||||||||||||||||||
Interest income and other income | 32 | 113 | 71 | 1,676 | ||||||||||||||
Interest expense | (24,726 | ) | (23,912 | ) | (49,268 | ) | (45,502 | ) | ||||||||||
Commodity derivative gain | (1) | 36,839 | 47,024 | 6,988 | 91,771 | |||||||||||||
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Total other income and expense | 12,145 | 23,225 | (42,209 | ) | 47,945 | |||||||||||||
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Income (Loss) before Income Taxes | 22,876 | 5,678 | (29,702 | ) | 63,851 | |||||||||||||
Provision for (Benefit from) Income Taxes | 8,603 | 2,380 | (10,824 | ) | 24,660 | |||||||||||||
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| |||||||||||
Net Income (Loss) | $ | 14,273 | $ | 3,298 | $ | (18,878 | ) | $ | 39,191 | |||||||||
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| |||||||||||
Net Income (Loss) Per Common Share | ||||||||||||||||||
Basic | $ | 0.30 | $ | 0.07 | $ | (0.40 | ) | $ | 0.83 | |||||||||
Diluted | $ | 0.30 | $ | 0.07 | $ | (0.40 | ) | $ | 0.83 | |||||||||
Weighted Average Common Shares Outstanding | ||||||||||||||||||
Basic | 47,469 | 47,202 | 47,411 | 47,143 | ||||||||||||||
Diluted | 47,616 | 47,245 | 47,411 | 47,335 | ||||||||||||||
| (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 June 30, | Six Months Ended June 30, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
Included in oil and gas production revenue: | ||||||||||||||||
Certain realized gains on hedges | $ | 1,936 | $ | 20,798 | $ | 4,003 | $ | 46,263 | ||||||||
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Included in commodity derivative gain (loss): | ||||||||||||||||
Realized gain (loss) on derivatives not designated as cash flow hedges | $ | (227 | ) | $ | 18,916 | $ | 6,226 | $ | 22,719 | |||||||
Unrealized gain on derivatives not designated as cash flow hedges | 37,066 | 28,108 | 762 | 69,052 | ||||||||||||
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Total commodity derivative gain (loss) | $ | 36,839 | $ | 47,024 | $ | 6,988 | $ | 91,771 | ||||||||
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| (2) | This separate presentation is a non-GAAP measure. 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, which may have higher or lower costs associated with stock-based grants. |
10
BILL BARRETT CORPORATION
Consolidated Condensed Balance Sheets
(Unaudited)
| As of June 30, 2013 | As of December 31, 2012 | |||||||||
| (in thousands) | ||||||||||
Assets: | ||||||||||
Cash and cash equivalents | $ | 62,875 | $ | 79,445 | ||||||
Other current assets | (1) | 120,349 | 148,894 | |||||||
Property and equipment, net | 2,698,054 | 2,611,337 | ||||||||
Other noncurrent assets | (1) | 33,889 | 29,773 | |||||||
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Total assets | $ | 2,915,167 | $ | 2,869,449 | ||||||
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Liabilities and Stockholders’ Equity: | ||||||||||
Current liabilities | (1) | $ | 202,745 | $ | 213,133 | |||||
Notes payable to bank | 80,000 | — | ||||||||
Capital lease | 83,868 | 88,519 | ||||||||
Senior notes | 1,043,652 | 1,042,791 | ||||||||
Convertible senior notes | 25,344 | 25,344 | ||||||||
Other long-term liabilities | (1) | 309,736 | 316,887 | |||||||
Stockholders’ equity | 1,169,822 | 1,182,775 | ||||||||
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Total liabilities and stockholders’ equity | $ | 2,915,167 | $ | 2,869,449 | ||||||
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| (1) | At June 30, 2013, the estimated fair value of all of the Company’s commodity derivative instruments was a net asset of $29.3 million, comprised of: $19.6 million current assets, $9.8 million non-current assets and $0.1 million current liabilities. This amount will fluctuate quarterly based on estimated future commodity prices and the current hedge position. |
11
BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| (in thousands) | ||||||||||||||||
Operating Activities: | ||||||||||||||||
Net income (loss) | $ | 14,273 | $ | 3,298 | $ | (18,878 | ) | $ | 39,191 | |||||||
Adjustments to reconcile to net cash provided by operations: | ||||||||||||||||
Depreciation, depletion and amortization | 74,307 | 85,942 | 142,745 | 160,025 | ||||||||||||
Impairment, dry hole costs and abandonment expense | 1,182 | 21,075 | 8,283 | 21,639 | ||||||||||||
Unrealized derivative gain | (37,066 | ) | (28,108 | ) | (762 | ) | (69,052 | ) | ||||||||
Deferred income taxes | 8,603 | 2,380 | (10,824 | ) | 24,660 | |||||||||||
Stock compensation and other non-cash charges | 3,219 | 4,318 | 9,289 | 7,640 | ||||||||||||
Amortization of debt discounts and deferred financing costs | 1,734 | 1,685 | 3,466 | 5,002 | ||||||||||||
Gain on sale of properties | (674 | ) | — | (4,193 | ) | — | ||||||||||
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Change in assets and liabilities: | ||||||||||||||||
Accounts receivable | (2,729 | ) | 2,929 | 16,506 | 18,136 | |||||||||||
Prepayments and other current assets | 767 | (7,257 | ) | 1,585 | (6,066 | ) | ||||||||||
Accounts payable, accrued and other liabilities | (9,654 | ) | 3,581 | (23,743 | ) | (8,853 | ) | |||||||||
Amounts payable to oil & gas property owners | 7,331 | (2,106 | ) | 9,737 | (5,383 | ) | ||||||||||
Production taxes payable | (5,190 | ) | (5,293 | ) | (10,182 | ) | (7,695 | ) | ||||||||
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Net cash provided by operating activities | $ | 56,103 | $ | 82,444 | $ | 123,029 | $ | 179,244 | ||||||||
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Investing Activities: | ||||||||||||||||
Additions to oil and gas properties, including acquisitions | (101,328 | ) | (229,901 | ) | (216,652 | ) | (460,059 | ) | ||||||||
Additions of furniture, equipment and other | (742 | ) | (1,912 | ) | (1,187 | ) | (4,241 | ) | ||||||||
Proceeds from sale of properties and other investing activities | (2,338 | ) | 246 | 4,086 | 134 | |||||||||||
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Net cash used in investing activities | $ | (104,408 | ) | $ | (231,567 | ) | $ | (213,753 | ) | $ | (464,166 | ) | ||||
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Financing Activities: | ||||||||||||||||
Proceeds from debt | 55,000 | 75,000 | 80,000 | 525,000 | ||||||||||||
Principal payments on debt | (2,260 | ) | — | (4,501 | ) | (267,156 | ) | |||||||||
Deferred financing costs and other | (85 | ) | (737 | ) | (1,348 | ) | (10,087 | ) | ||||||||
Proceeds from stock option exercises | 3 | — | 3 | 668 | ||||||||||||
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Net cash provided by financing activities | $ | 52,658 | $ | 74,263 | $ | 74,154 | $ | 248,425 | ||||||||
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Increase (Decrease) in Cash and Cash Equivalents | 4,353 | (74,860 | ) | (16,570 | ) | (36,497 | ) | |||||||||
Beginning Cash and Cash Equivalents | 58,522 | 95,694 | 79,445 | 57,331 | ||||||||||||
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Ending Cash and Cash Equivalents | $ | 62,875 | $ | 20,834 | $ | 62,875 | $ | 20,834 | ||||||||
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12
BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow & Adjusted Net Income
(Unaudited)
Discretionary Cash Flow Reconciliation
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
(in thousands, except per share amounts) | ||||||||||||||||
Net Income (Loss) | $ | 14,273 | $ | 3,298 | $ | (18,878 | ) | $ | 39,191 | |||||||
Adjustments to reconcile to discretionary cash flow: | ||||||||||||||||
Depreciation, depletion and amortization | 74,307 | 85,942 | 142,745 | 160,025 | ||||||||||||
Impairment, dry hole and abandonment expense | 1,182 | 21,075 | 8,283 | 21,639 | ||||||||||||
Exploration expense | 141 | 4,062 | 236 | 4,501 | ||||||||||||
Unrealized derivative gain | (37,066 | ) | (28,108 | ) | (762 | ) | (69,052 | ) | ||||||||
Deferred income taxes | 8,603 | 2,380 | (10,824 | ) | 24,660 | |||||||||||
Stock compensation and other non-cash charges | 3,219 | 4,318 | 9,289 | 7,640 | ||||||||||||
Amortization of debt discounts and deferred financing costs | 1,734 | 1,685 | 3,466 | 6,603 | ||||||||||||
Gain on extinguishment of debt | — | — | — | (1,601 | ) | |||||||||||
Gain on sale of properties | (674 | ) | — | (4,193 | ) | — | ||||||||||
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Discretionary Cash Flow | $ | 65,719 | $ | 94,652 | $ | 129,362 | $ | 193,606 | ||||||||
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Per share, diluted | $ | 1.38 | $ | 2.00 | $ | 2.73 | $ | 4.09 | ||||||||
Per Mcfe | $ | 3.08 | $ | 3.17 | $ | 3.04 | $ | 3.33 | ||||||||
Adjusted Net Income (Loss) Reconciliation
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
(in thousands except per share amounts) | ||||||||||||||||
Net Income (Loss) | $ | 14,273 | $ | 3,298 | $ | (18,878 | ) | $ | 39,191 | |||||||
Adjustments to net income (loss): | ||||||||||||||||
Unrealized derivative gain | (37,066 | ) | (28,108 | ) | (762 | ) | (69,052 | ) | ||||||||
Impairment expense | — | 18,337 | — | 18,337 | ||||||||||||
Gain on sale of properties | (674 | ) | — | (4,193 | ) | — | ||||||||||
One time items: | ||||||||||||||||
Expenses relating to compressor station fire | — | — | 1,175 | — | ||||||||||||
Gain on extinguishment of debt | — | — | — | (1,601 | ) | |||||||||||
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Subtotal Adjustments | (37,740 | ) | (9,771 | ) | (3,780 | ) | (52,316 | ) | ||||||||
Effective tax rate | 38 | % | 42 | % | 36 | % | 39 | % | ||||||||
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Tax effected adjustments | (23,399 | ) | (5,667 | ) | (2,419 | ) | (31,913 | ) | ||||||||
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Adjusted Net Income (Loss) | $ | (9,126 | ) | $ | (2,369 | ) | $ | (21,297 | ) | $ | 7,278 | |||||
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Per share, diluted | $ | (0.19 | ) | $ | (0.05 | ) | $ | (0.45 | ) | $ | 0.15 | |||||
Per Mcfe | $ | (0.43 | ) | $ | (0.08 | ) | $ | (0.50 | ) | $ | 0.13 | |||||
Discretionary cash flow and adjusted net income are non-GAAP measures. These measures 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 (loss) for unusual items to allow for a more consistent comparison from period to period. In addition, the Company believes that 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 that 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 necessarily all, items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similarly titled measures of other companies.
13