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Bill Barrett Corporation Reports Fourth Quarter and Year-End 2017 Financial and Operating Results; Highlighted by Quarterly Production of 2.12 MMBoe, 42% Growth in DJ Basin Volumes and 56% Increase in Proved Reserves

DENVER, Feb. 27, 2018 /PRNewswire/ -- 

  • Announced strategic combination with Fifth Creek Energy that materially expands DJ Basin footprint and significantly strengthens balance sheet
  • Production sales volumes of 7.0 million barrels of oil equivalent ("MMBoe") in 2017 represents 20% growth over 2016, pro forma for asset sales
  • Production sales volumes of 2.12 MMBoe in the fourth quarter of 2017 represents 37% growth over the fourth quarter of 2016; Denver-Julesburg ("DJ") Basin production of 1.94 MMBoe represents 42% growth over the fourth quarter of 2016
  • DJ Basin lease operating expense ("LOE") of $2.64 per Boe in the fourth quarter of 2017 represents an 11% improvement compared to the fourth quarter of 2016
  • Extended reach lateral ("XRL") wells averaged $4.65 million in 2017, driven by a 30% improvement in drilling and completion cycle times compared to 2016
  • Year-end 2017 proved reserves of 86 MMBoe represents a 56% increase over year-end 2016 proved reserves with estimated all-sources reserve replacement of 541%
  • Completed sale of remaining Uinta Basin assets for net proceeds of $102 million
  • Entered 2018 with $314 million of cash and an undrawn credit facility of $300 million providing strong liquidity to fund anticipated 2018 activity levels

Bill Barrett Corporation (the "Company") (NYSE: BBG) today reported fourth quarter and full year 2017 financial and operating results and provides first quarter of 2018 outlook on its legacy properties.

Chief Executive Officer and President Scot Woodall commented, "Reflecting on the past year, I'm proud of our accomplishments as we delivered excellent operating and financial results, and executed on strategic goals as well. Our strong execution was highlighted by 2017 production growth of 20%, further improvement in per unit operating costs and lower oil price differentials that translated into industry leading operating margins relative to our DJ Basin peers. Our operations team did an excellent job of executing an efficient capital program that resulted in strong reserve and production growth from our legacy DJ Basin asset. We are also seeing positive results from our enhanced completion program. During the fourth quarter, we completed the sale of our remaining Uinta Basin assets, a transaction that further streamlines our operations and cost structure, while strengthening our balance sheet. We have generated significant operating momentum and entered 2018 with $314 million of cash and an undrawn credit facility of $300 million, providing strong liquidity to support anticipated 2018 activity levels."

Mr. Woodall continued, "In December, we announced a strategic combination with Fifth Creek Energy that creates a premier DJ Basin company. This transaction significantly expands our footprint by providing a large, derisked acreage position with a significant inventory of drilling locations, while materially improving our leverage metrics. We continue to integrate the two organizations and expect to provide a combined 2018 operating plan and guidance following the anticipated March closing."

For the fourth quarter of 2017, the Company reported a net loss of $77.8 million, or $0.94 per diluted share. Adjusted net income (non-GAAP) for the fourth quarter of 2017 was $1.1 million, or $0.01 per diluted share. EBITDAX for the fourth quarter of 2017 was $57.3 million. For 2017 as a whole, the Company reported a net loss of $138.2 million, or $1.80 per diluted share. Adjusted net income (non-GAAP) for 2017 was a net loss of $29.2 million, or $0.38 per diluted share. EBITDAX for 2017 was $178.0 million. Adjusted net income (loss) and EBITDAX are non-GAAP (Generally Accepted Accounting Principles) measures. Please reference the reconciliations to GAAP financial statements at the end of this release.

Strategic Combination with Fifth Creek Energy

On December 5, 2017, the Company announced a strategic combination with Fifth Creek Energy that materially expands its DJ Basin footprint and, coupled with other strategic steps taken in the fourth quarter of 2017, significantly strengthens the Company's balance sheet. The Company has established a record date of February 13, 2018, and a date of March 16, 2018, for a special meeting of its shareholders to vote on, among other items, the strategic business combination with Fifth Creek Energy pursuant to the Agreement and Plan of Merger. The combination is expected to close in March 2018.

OPERATING AND FINANCIAL RESULTS

Proved Reserves

Total estimated proved reserves at year-end 2017 were 85.8 MMBoe compared to 54.9 MMBoe at year-end 2016, an increase of 56%. All-sources reserve replacement totaled 541%(1). The increase in estimated proved reserves compared to year-end 2016 is primarily the result of extensions and discoveries of 35.9 MMBoe, and positive commodity price-related and other revisions totaling 8.8 MMBoe, partially offset by sale of properties of 11.2 MMBoe. Additions to extensions and discoveries were driven by positive drilling results in the DJ Basin, which resulted in a 100% increase in DJ Basin proved reserves. The Company maintained a conservative approach to adding proved undeveloped ("PUD") locations by limiting the PUD inventory to only two rig years of planned drilling activity. Sale of properties primarily consisted of the sale of Uinta Basin assets, which was completed in December 2017. Positive price-related revisions were primarily a result of a 20% increase in both the average WTI oil price and the average Henry Hub natural gas price used to calculate the 2017 proved reserves compared to 2016.

Changes in Proved Reserves (MMBoe)

Proved reserves as of December 31, 2016

54.9

Extensions and discoveries

35.9

Production sales volumes

(7.0)

Purchases of oil and gas reserves in place

4.4

Sale of properties

(11.2)

Pricing revisions and other

8.8

Proved reserves as of December 31, 2017

85.8


1 All-sources reserve replacement defined as the sum of the year-over-year net additions in provided reserves from extensions and discoveries, pricing revisions, sale of properties, divided by 2017 production sales volumes

2017 Production and Financial Results

Oil, natural gas and natural gas liquids production totaled 7.0 MMBoe for 2017, at the mid-point of the Company's guidance range of 6.9-7.1 MMBoe. DJ Basin production sales volumes totaled 6.2 MMBoe for 2017 or an increase of 21% compared to 2016. Production sales volumes for 2017 were weighted 60% oil, 21% natural gas and 19% natural gas liquids. 

Production sales volumes for the fourth quarter of 2017 totaled 2.12 MMBoe, above the mid-point of the Company's guidance range of 2.0-2.2 MMBoe, representing a 37% increase from the fourth quarter of 2016. DJ Basin production sales volumes totaled 1.94 MMBoe, an increase of 42% compared to the fourth quarter of 2016. DJ Basin oil volumes totaled 1.1 MMBbls, an increase of 38% compared to the fourth quarter of 2016. Production sales volumes for the fourth quarter of 2017 were weighted 60% oil, 23% natural gas and 17% NGLs.


Three Months Ended
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016

Production Data (1)








Oil (MBbls)

1,274



960



4,203



3,885


Natural gas (MMcf)

2,868



1,866



8,952



7,170


NGLs (MBbls)

371



279



1,307



1,010


Combined volumes (MBoe)

2,123



1,550



7,002



6,090


Daily combined volumes (Boe/d)

23,076



16,848



19,184



16,639



(1) Includes legacy DJ Basin and Uinta Basin production only

For 2017, West Texas Intermediate ("WTI") oil prices averaged $50.95 per barrel, NWPL natural gas prices averaged $2.71 per MMBtu and NYMEX natural gas prices averaged $3.11 per MMBtu. Commodity price differentials to benchmark pricing for 2017 were oil less $2.75 per barrel versus WTI; and natural gas less $0.27 per Mcf compared to NWPL. The DJ Basin oil price differential averaged $2.40 per barrel. The NGL price averaged approximately 39% of the WTI price per barrel.

For the fourth quarter of 2017, WTI oil prices averaged $55.40 per barrel, NWPL natural gas prices averaged $2.60 per MMBtu and NYMEX natural gas prices averaged $2.93 per MMBtu. Fourth quarter of 2017 commodity price differentials to benchmark pricing were oil less $2.44 per barrel versus WTI; and natural gas less $0.28 per Mcf compared to NWPL. The DJ Basin oil price differential averaged $2.51 per barrel. The NGL price averaged approximately 44% of the WTI price per barrel.

For the fourth quarter of 2017, the Company had derivative commodity swaps in place for 8,125 barrels of oil per day tied to WTI pricing at $57.69 per barrel, 10,000 MMBtu of natural gas per day tied to NWPL regional pricing at $2.96 per MMBtu and no hedges in place for NGLs.


Three Months Ended
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016

Average Sales Prices (before the effects of realized hedges):

Oil (per Bbl)

$

52.63



$

44.76



$

48.37



$

38.83


Natural gas (per Mcf)

2.32



2.47



2.43



1.98


NGLs (per Bbl)

24.09



16.04



20.01



13.15


Combined (per Boe)

38.94



33.57



35.88



29.28










Average Realized Sales Prices (after the effects of realized hedges):

Oil (per Bbl)

$

53.98



$

62.03



$

52.72



$

62.56


Natural gas (per Mcf)

2.43



2.80



2.52



2.46


NGLs (per Bbl)

24.09



16.04



20.01



13.15


Combined (per Boe)

39.90



44.65



38.60



44.98


Cash operating costs (LOE, gathering, transportation and processing costs, and production tax expense) averaged $5.90 per Boe in 2017 compared to $6.72 per Boe in 2016, a 12% improvement. Cash operating costs totaled $6.24 per Boe in the fourth quarter of 2017 compared to $6.37 per Boe in the fourth quarter of 2016. 

LOE was $3.27 per Boe in the fourth quarter of 2017 compared to $3.73 per Boe in the fourth quarter of 2016. The year-over-year improvement was primarily a result of increased operational efficiencies and lease operating cost reductions.

DJ Basin LOE improved to $2.64 per Boe in the fourth quarter of 2017 compared to $2.96 per Boe in the fourth quarter of 2016, and was $2.87 per Boe in 2017 compared to $3.41 per Boe in 2016.


Three Months Ended
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016

Average Costs (per Boe):








Lease operating expenses

$

3.27



$

3.73



$

3.46



$

4.58


Gathering, transportation and processing expense

0.46



0.32



0.37



0.39


Production tax expenses

2.51



2.32



2.07



1.75


Depreciation, depletion and amortization

19.10



29.76



22.85



28.18


General and administrative expense

5.51



6.86



6.07



6.92


The following table summarizes certain operating and financial results for the fourth quarter of 2017 and 2016 and the full years 2017 and 2016:


Three Months Ended
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016

Production sales volumes (MBoe)

2,123



1,550



7,002



6,090


Net cash provided by (used in) operating activities ($ millions)

$

26.6



$

5.5



$

122.0



$

121.7


Discretionary cash flow ($ millions) (1)

$

45.9



$

32.4



$

125.3



$

126.1


Net income (loss) ($ millions)

$

(77.8)



$

(49.3)



$

(138.2)



$

(170.4)


Per share, basic

$

(0.94)



$

(0.79)



$

(1.80)



$

(3.08)


Per share, diluted

$

(0.94)



$

(0.79)



$

(1.80)



$

(3.08)


Adjusted net income (loss) ($ millions) (1)

$

1.1



$

(11.2)



$

(29.2)



$

(37.8)


Per share, basic

$

0.01



$

(0.18)



$

(0.38)



$

(0.68)


Per share, diluted

$

0.01



$

(0.18)



$

(0.38)



$

(0.68)


Weighted average shares outstanding, basic (in thousands)

83,138



62,241



76,859



55,384


Weighted average shares outstanding, diluted (in thousands)

83,138



62,241



76,859



55,384


EBITDAX ($ millions) (1)

$

57.3



$

45.8



$

178.0



$

182.4




(1)

Discretionary cash flow, adjusted net income (loss) and EBITDAX are non-GAAP (Generally Accepted Accounting Principles) measures. Please reference the reconciliations to GAAP financial statements at the end of this release.

At December 31, 2017, the Company's $300 million revolving credit facility had zero drawn and $274.0 million in available capacity, after taking into account a $26.0 million letter of credit. The principal balance of long-term debt was $627.3 million and cash and cash equivalents were $314.5 million, resulting in net debt (principal balance of debt outstanding less the cash and cash equivalents balance) of $312.8 million. Cash and cash equivalents includes approximately $110.8 million of net proceeds from the common stock offering completed in December 2017 and $102.3 million of net proceeds from the sale of Uinta Basin properties that closed in December 2017.

On December 5, 2017, the Company announced a privately negotiated exchange with a holder of its 7.0% Senior Notes due 2022 (the "Notes"). As a result of this transaction, the principal amount of the Notes was reduced by $50 million or 13%, which will result in annual interest savings of approximately $3.5 million.

Capital Expenditures

Capital expenditures of $260.7 million for 2017 were at the mid-point of the Company's guidance range of $250-$270 million. Capital projects included spudding 69 gross operated XRL wells in the DJ Basin and placing 54 gross operated XRL wells on initial flowback. Completion activity was greater during the second half of the year as the Company entered 2017 operating one drilling rig and added a second drilling rig in June. Capital expenditures included $226.9 million for drilling and completion operations, $20.4 million for leaseholds to expand development programs, and $13.4 million for infrastructure and corporate purposes.

Capital expenditures for the fourth quarter of 2017 totaled $86.2 million, which was at the mid-point of the Company's guidance range of $80-$90 million. Capital expenditures included spudding 22 gross operated XRL wells in the DJ Basin and placing 16 gross operated XRL wells on initial flowback. Capital expenditures included $76.8 million for drilling and completion operations, $0.2 million for leaseholds, and $9.2 million for infrastructure and corporate assets.

OPERATIONAL HIGHLIGHTS

DJ Basin

During 2017, production sales volumes from the DJ Basin totaled 6.2 MMBoe, which represents a 23% increase over 2016. In the fourth quarter of 2017, DJ Basin production sales volumes totaled 1.94 MMBoe, which represents a 42% increase from the fourth quarter of 2016. DJ Basin oil volumes totaled 1.11 MMBbls, which represents a 38% increase from the fourth quarter of 2016.

During 2017, the DJ Basin program focused on optimizing completions to include enhanced completions and narrower frac stage spacing of approximately 120 feet. Early data from the enhanced completion program is encouraging with well performance from recent DSUs on average meeting or exceeding the base XRL type-curve of 600 MBoe.

Completion activity was recently highlighted by DSU 5-63-32 and DSU 5-63-30, which are located within the western area of NE Wattenberg and include 5 XRL and 6 XRL wells, respectively. Initial flowback began in the third quarter of 2017 and production is tracking above the base type-curve. DSU 5-61-20 is located within the central area of NE Wattenberg and includes 8 XRL wells. Initial flowback began in the fourth quarter of 2017 and the wells are performing consistent with the base type-curve.

Two drilling rigs are currently operating in the NE Wattenberg field with drilling activity focused on the southern portion of the acreage position within DSU 4-62-28, which includes 10 XRL wells, and within DSU 4-62-33, which includes 10 XRL wells. In addition, completion operations continue at DSU 3-62-4, which includes 10 XRL wells and is expected to be placed on initial flowback in the first quarter 2018.

The drilling program continues to exceed expectations as XRL well drilling days to rig release averaged approximately 6.9 days per well in 2017, including a best-in-class XRL well that was drilled in approximately 5.6 days. This represents a 15% improvement from the average of 2016.

Drilling and completion efficiencies continue to be achieved within the XRL well program that have resulted in an approximate 30% average year-over-year improvement in 2017 cycle times leading to an increased number of stages being completed and in the amount of sand that is pumped on a daily basis.

Drilling and completion costs for XRL wells averaged approximately $4.65 million in 2017 and the Company continues to seek efficiencies that will offset expected inflationary pressures in 2018.

Uinta Oil Program

Production sales volumes averaged 1,965 Boe/d (91% oil) during the fourth quarter of 2017.

The Company completed the sale of its Uinta Basin assets for net proceeds of $102 million in December 2017.

FIRST QUARTER 2018 OUTLOOK

The Company is providing its outlook for the first quarter of 2018 for its legacy properties and anticipates issuing full year 2018 guidance following the closing of the Fifth Creek Energy transaction in March 2018. See "Forward-Looking Statements" below.

  • Capital expenditures are expected to total approximately $80-$90 million
    • Assumes two drilling rigs operating in NE Wattenberg
  • Production of 1.8-2.0 MMBoe
    • Includes only DJ Basin production volumes on the legacy NE Wattenberg acreage and does not include any volumes associated with the Uinta Basin that was sold in the fourth quarter of 2017 or from the Fifth Creek Energy business combination
    • Represents flat sequential production from the fourth quarter of 2017 as operations are being modestly impacted by high line pressures associated with third-party natural gas processing constraints and third-party line freezes
    • Production is estimated to be approximately 60% oil

COMMODITY HEDGES UPDATE

Generally, it is the Company's strategy to hedge 50%-70% of production on a forward 12-month to 18-month basis to reduce the risks associated with unpredictable future commodity prices, to provide certainty for a portion of its cash flow and to support its capital expenditure program.

For 2018, 10,067 barrels per day of oil is hedged at an average WTI price of $53.55 per barrel and 5,000 MMBtu/d of natural gas is hedged at an average NWPL price of $2.68 per MMBtu.

For 2019, 5,246 barrels per day of oil is hedged at an average WTI price of $54.17 per barrel. No natural gas hedges are in place.

As of February 27, 2018, the Company had the following commodity hedge positions in place on its legacy properties for 2018 and 2019:



Oil (WTI)


Natural Gas (NWPL)

Period


Volume
Bbls/d


Price
$/Bbl


Volume
MMBtu/d


Price
$/MMBtu

1Q18


9,250



$

52.99



5,000



$

2.68


2Q18


10,000



53.28



5,000



2.68


3Q18


10,500



53.92



5,000



2.68


4Q18


10,500



53.92



5,000



2.68


1Q19


5,750



54.25






2Q19


5,750



54.25






3Q19


4,750



54.07






4Q19


4,750



54.07






Realized sales prices will reflect basis differentials from the index prices to the sales location.

UPCOMING EVENTS
Teleconference Call and Webcast

The Company plans to host a conference call on Wednesday, February 28, 2018, to discuss the results and other items presented in this press release. The call is scheduled at 10:00 a.m. Eastern time (8:00 a.m. Mountain time). Please join the webcast conference call live or for replay via the Internet at www.billbarrettcorp.com, accessible from the home page. To join by telephone, call 855-760-8152 (631-485-4979 international callers) with passcode 9658234. The webcast will remain on the Company's website for approximately 30 days and a replay of the call will be available through Wednesday, March 7, 2018 at 855-859-2056 (404-537-3406 international) with passcode 9658234.

Investor Events

Members of management are scheduled to participate in the following investor event:

  • March 26-27, 2018 - Scotia Howard Weil Energy Conference in New Orleans, LA

Presentation materials will be posted to the Company's website at www.billbarrettcorp.com in the Investor Relations section prior to the start of the conference.

ADDITIONAL INFORMATION AND WHERE TO FIND IT

In connection with the proposed transaction with Fifth Creek Energy, the Company and Fifth Creek Energy caused the newly formed company ("Holdco") to file with the SEC a registration statement on Form S-4, which includes a prospectus with respect to the shares of Holdco to be issued in the proposed transaction and a proxy statement of the Company with respect to the obtaining of stockholder approval for the transaction.  The registration statement was declared effective by the SEC on February 13, 2018.  On or about February 14, 2018, the Company commenced mailing the definitive proxy statement/prospectus to its stockholders of record as of the close of business on February 13, 2018.  The Company and Holdco also plan to file other documents with the SEC regarding the proposed transaction.  STOCKHOLDERS OF THE COMPANY ARE URGED TO READ THE REGISTRATION STATEMENT AND PROXY STATEMENT/PROSPECTUS (INCLUDING ALL AMENDMENTS AND SUPPLEMENTS THERETO) AND OTHER DOCUMENTS RELATING TO THE PROPOSED TRANSACTION THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION.  Investors may obtain free copies of the proxy statement/prospectus and other documents containing important information about Holdco, the Company and Fifth Creek Energy through the website maintained by the SEC at http://www.sec.gov. Copies of the documents filed with the SEC by the Company are available free of charge on the Company's internet website at www.billbarrettcorp.com under the tab "Investors" and then under the tab "SEC Filings" or by contacting the Company's Investor Relations Department at (303) 293‐9100.

PARTICIPANTS IN THE SOLICITATION

Holdco, the Company, and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in connection with the proposed Fifth Creek Energy transaction.  Information about the Company's directors and executive officers is set forth in the Company's public filings with the SEC, including its definitive proxy statement filed with the SEC on April 6, 2017. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, is contained in the proxy statement/prospectus referred to in the preceding paragraph and other relevant materials filed with the SEC. Free copies of these documents can be obtained as described in the preceding paragraph.

NO OFFER OR SOLICITATION

This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities, or a solicitation of any vote or approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended (the "Securities Act").

DISCLOSURE STATEMENTS

Forward-Looking Statements

All statements in this press release, other than statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934. Words such as expects, forecast, guidance, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein; however, these are not the exclusive means of identifying forward-looking statements. In particular, the Company is providing "First Quarter 2018 Outlook," which contains projections for certain first quarter 2018 operational metrics. Additional forward-looking statements in this release relate to, among other things, the closing and effect of the Fifth Creek Energy transaction, future capital expenditures, projects, costs, operational improvements and opportunities.

These and other forward-looking statements in this press release are based on management's judgment as of the date of this release and are subject to numerous risks and uncertainties. Actual results may vary significantly from those indicated in the forward-looking statements due to, among other things: oil, NGL and natural gas price volatility, including regional price differentials; changes in operational and capital plans; changes in capital costs, operating costs, availability and timing of build-out of third-party facilities for gathering, processing, refining and transportation; delays or other impediments to drilling and completing wells arising from political or judicial developments at the local, state or federal level, including voter initiatives related to hydraulic fracturing; development drilling and testing results; the potential for production decline rates to be greater than expected; regulatory delays, including seasonal or other wildlife restrictions on federal lands; exploration risks such as drilling unsuccessful wells; higher than expected costs and expenses, including the availability and cost of services and materials, and our potential inability to achieve expected cost savings; unexpected future capital expenditures; economic and competitive conditions; debt and equity market conditions, including the availability and costs of financing to fund the Company's operations; 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, including new emission control requirements; derivative and hedging activities; risks associated with operating in one major geographic area; the success of the Company's risk management activities; unexpected obstacles to closing anticipated transactions, including the Fifth Creek Energy transaction, or unfavorable purchase price adjustments; title to properties; litigation; and environmental liabilities; and potential failure to achieve the anticipated benefits of the Fifth Creek Energy transaction. Please refer to the Company's Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC and for the year 2017 upon filing, and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, all of which are incorporated by reference herein, for further discussion of risk factors that may affect the forward-looking statements. The Company encourages you to consider the risks and uncertainties associated with projections and other forward-looking statements and not to place undue reliance on any such 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, develops oil and natural gas in the Rocky Mountain region of the United States. Additional information about the Company may be found on its website at www.billbarrettcorp.com.

BILL BARRETT CORPORATION

Selected Operating Highlights

(Unaudited)



Three Months Ended
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016

Production Data:








Oil (MBbls)

1,274



960



4,203



3,885


Natural gas (MMcf)

2,868



1,866



8,952



7,170


NGLs (MBbls)

371



279



1,307



1,010


Combined volumes (MBoe)

2,123



1,550



7,002



6,090


Daily combined volumes (Boe/d)

23,076



16,848



19,184



16,639










Average Sales Prices (before the effects of realized hedges):

Oil (per Bbl)

$

52.63



$

44.76



$

48.37



$

38.83


Natural gas (per Mcf)

2.32



2.47



2.43



1.98


NGLs (per Bbl)

24.09



16.04



20.01



13.15


Combined (per Boe)

38.94



33.57



35.88



29.28










Average Realized Sales Prices (after the effects of realized hedges):

Oil (per Bbl)

$

53.98



$

62.03



$

52.72



$

62.56


Natural gas (per Mcf)

2.43



2.80



2.52



2.46


NGLs (per Bbl)

24.09



16.04



20.01



13.15


Combined (per Boe)

39.90



44.65



38.60



44.98










Average Costs (per Boe):








Lease operating expenses

$

3.27



$

3.73



$

3.46



$

4.58


Gathering, transportation and processing expense

0.46



0.32



0.37



0.39


Production tax expenses

2.51



2.32



2.07



1.75


Depreciation, depletion and amortization

19.10



29.76



22.85



28.18


General and administrative expense (1)

5.51



6.86



6.07



6.92




(1)

Includes long-term cash and equity incentive compensation of $1.32 per Boe and $2.12 per Boe for the three months ended December 31, 2017 and 2016, respectively, and $1.18 per Boe and $1.96 per Boe for the twelve months ended December 31, 2017 and 2016, respectively.


 

BILL BARRETT CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)



As of
December 31,


As of

December 31,


2017


2016


(in thousands)

Assets:




Cash and cash equivalents

$

314,466



$

275,841


Other current assets (1)

53,197



42,611


Property and equipment, net

1,018,880



1,062,149


Other noncurrent assets

4,163



4,740


Total assets

$

1,390,706



$

1,385,341






Liabilities and Stockholders' Equity:




Current liabilities (1)

$

148,934



$

85,018


Long-term debt, net of debt issuance costs

617,744



711,808


Other long-term liabilities (1)

25,474



16,972


Stockholders' equity

598,554



571,543


Total liabilities and stockholders' equity

$

1,390,706



$

1,385,341




(1)

At December 31, 2017, the estimated fair value of all of the Company's commodity derivative instruments was a net liability of $25.1 million, comprised of $20.9 million of current liabilities and $4.2 million of noncurrent liabilities. This amount will fluctuate based on estimated future commodity prices and the current hedge position.

 

BILL BARRETT CORPORATION

Consolidated Statements of Operations

(Unaudited)



Three Months Ended
December 31,


Twelve Months Ended
December 31,


2017


2016


2017


2016


(in thousands, except per share amounts)

Operating Revenues:








Oil, gas and NGL production

$

82,674



$

52,049



$

251,215



$

178,328


Other operating revenues

698



(429)



1,624



491


Total operating revenues

83,372



51,620



252,839



178,819


Operating Expenses:








Lease operating expense

6,936



5,785



24,223



27,886


Gathering, transportation and processing expense

971



494



2,615



2,365


Production tax expense

5,336



3,601



14,476



10,638


Exploration expense

35



19



83



83


Impairment, dry hole costs and abandonment expense

41,217



2,483



49,553



4,249


(Gain) loss on sale of properties



(128)



(92)



1,078


Depreciation, depletion and amortization

40,555



46,150



159,964



171,641


Unused commitments

4,544



4,569



18,231



18,272


General and administrative expense (1)

11,688



10,634



42,476



42,169


Merger transaction expense

8,749





8,749




Other operating expenses, net

96



(316)



(1,514)



(316)


Total operating expenses

120,127



73,291



318,764



278,065


Operating Income (Loss)

(36,755)



(21,671)



(65,925)



(99,246)


Other Income and Expense:








Interest and other income

329



69



1,359



235


Interest expense

(13,696)



(14,213)



(57,710)



(59,373)


Commodity derivative gain (loss) (2)

(28,766)



(13,462)



(9,112)



(20,720)


Gain (loss) on extinguishment of debt

(335)





(8,239)



8,726


Total other income and expense

(42,468)



(27,606)



(73,702)



(71,132)


Income (Loss) before Income Taxes

(79,223)



(49,277)



(139,627)



(170,378)


(Provision for) Benefit from Income Taxes

1,402





1,402




Net Income (Loss)

$

(77,821)



$

(49,277)



$

(138,225)



$

(170,378)










Net Income (Loss) per Common Share








Basic

$

(0.94)



$

(0.79)



$

(1.80)



$

(3.08)


Diluted

$

(0.94)



$

(0.79)



$

(1.80)



$

(3.08)


Weighted Average Common Shares Outstanding








Basic

83,138



62,241



76,859



55,384


Diluted

83,138



62,241



76,859



55,384




(1)

Includes long-term cash and equity incentive compensation of $2.8 million and $3.3 million for the three months ended December 31, 2017 and 2016, respectively, and $8.3 million and $11.9 million for the twelve months ended December 31, 2017 and 2016, respectively.

(2)

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
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016


(in thousands)

Included in commodity derivative gain (loss):








Realized gain (loss) on derivatives

$

2,037



$

17,181



$

19,099



$

95,598


Reversal of prior year unrealized gain transferred to realized gain

(903)



(20,754)



(4,053)



(99,809)


Unrealized gain (loss) on derivatives

(29,900)



(9,889)



(24,158)



(16,509)


Total commodity derivative gain (loss)

$

(28,766)



$

(13,462)



$

(9,112)



$

(20,720)


 

BILL BARRETT CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)



Three Months Ended
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016


(in thousands)

Operating Activities:








Net income (loss)

$

(77,821)



$

(49,277)



$

(138,225)



$

(170,378)


Adjustments to reconcile to net cash provided by operations:

Depreciation, depletion and amortization

40,555



46,150



159,964



171,641


Impairment, dry hole costs and abandonment expense

41,217



2,483



49,553



4,249


Unrealized derivative (gain) loss

30,803



30,643



28,211



116,318


Incentive compensation and other non-cash charges

1,462



1,774



6,596



8,982


Amortization of debt discounts and deferred financing costs

529



759



2,194



2,834


(Gain) loss on sale of properties



(128)



(92)



1,078


(Gain) loss on extinguishment of debt

335





8,239



(8,726)


Change in operating assets and liabilities:








Accounts receivable

(9,326)



(2,928)



(18,578)



10,624


Prepayments and other assets

(868)



1,318



(1,848)



350


Accounts payable, accrued and other liabilities

(8,381)



(21,796)



11,690



(2,893)


Amounts payable to oil and gas property owners

4,031



(6,571)



10,402



(9,465)


Production taxes payable

4,071



3,102



3,884



(2,878)


Net cash provided by (used in) operating activities

$

26,607



$

5,529



$

121,990



$

121,736


Investing Activities:








Additions to oil and gas properties, including acquisitions

(78,843)



(13,166)



(239,631)



(106,870)


Additions of furniture, equipment and other

(658)



(11)



(926)



(1,195)


Proceeds from sale of properties and other investing activities

102,258



(644)



101,546



24,927


Net cash provided by (used in) investing activities

$

22,757



$

(13,821)



$

(139,011)



$

(83,138)


Financing Activities:








Proceeds from debt





275,000




Principal and redemption premium payments on debt

(115)



(111)



(322,343)



(440)


Deferred financing costs and other

(1,676)



(21)



(7,721)



(1,156)


Proceeds from sale of common stock, net of offering costs

111,008



110,002



110,710



110,003


Net cash provided by (used in) financing activities

$

109,217



$

109,870



$

55,646



$

108,407


Increase (Decrease) in Cash and Cash Equivalents

158,581



101,578



38,625



147,005


Beginning Cash and Cash Equivalents

155,885



174,263



275,841



128,836


Ending Cash and Cash Equivalents

$

314,466



$

275,841



$

314,466



$

275,841


 

BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow, Adjusted Net Income (Loss) and EBITDAX

(Unaudited)


Discretionary Cash Flow Reconciliation



Three Months Ended
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016


(in thousands)

Net Cash Provided by (Used in) Operating Activities

$

26,607



$

5,529



$

121,990



$

121,736


Adjustments to reconcile to discretionary cash flow:








Exploration expense

35



19



83



83


Merger transaction expense

8,749





8,749




Changes in working capital

10,473



26,875



(5,550)



4,262


Discretionary Cash Flow

$

45,864



$

32,423



$

125,272



$

126,081



Adjusted Net Income (Loss) Reconciliation



Three Months Ended
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016


(in thousands, except per share amounts)

Net Income (Loss)

$

(77,821)



$

(49,277)



$

(138,225)



$

(170,378)


  Provision for (Benefit from) income taxes

(1,402)





(1,402)




Income (Loss) before Income Taxes

(79,223)



(49,277)



(139,627)



(170,378)


Adjustments to Net Income (Loss):








Unrealized derivative (gain) loss

30,803



30,643



28,211



116,318


Impairment expense

41,088





49,098



183


(Gain) loss on sale of properties



(128)



(92)



1,078


(Gain) loss on extinguishment of debt

335





8,239



(8,726)


One-time items:








Merger transaction expense

8,749





8,749




(Income) expense related to properties sold

96



576



(1,514)



576


Adjusted Income (Loss) before Income Taxes

1,848



(18,186)



(46,936)



(60,949)


Adjusted (provision for) benefit from income taxes (1)

(700)



7,003



17,760



23,167


Adjusted Net Income (Loss)

$

1,148



$

(11,183)



$

(29,176)



$

(37,782)


Per share, diluted

$

0.01



$

(0.18)



$

(0.38)



$

(0.68)




(1)

Adjusted (provision for) benefit from income taxes is calculated using the Company's current effective tax rate prior to applying the valuation allowance against deferred tax assets.

 

EBITDAX Reconciliation



Three Months Ended
 December 31,


Twelve Months Ended
 December 31,


2017


2016


2017


2016


(in thousands)

Net Income (Loss)

$

(77,821)



$

(49,277)



$

(138,225)



$

(170,378)


Adjustments to reconcile to EBITDAX:








Depreciation, depletion and amortization

40,555



46,150



159,964



171,641


Impairment, dry hole and abandonment expense

41,217



2,483



49,553



4,249


Exploration expense

35



19



83



83


Unrealized derivative (gain) loss

30,803



30,643



28,211



116,318


Incentive compensation and other non-cash charges

1,462



1,774



6,596



8,982


Merger transaction expense

8,749





8,749




(Gain) loss on sale of properties



(128)



(92)



1,078


(Gain) loss on extinguishment of debt

335





8,239



(8,726)


Interest and other income

(329)



(69)



(1,359)



(235)


Interest expense

13,696



14,213



57,710



59,373


Provision for (benefit from) income taxes

(1,402)





(1,402)




EBITDAX

$

57,300



$

45,808



$

178,027



$

182,385


Discretionary cash flow and adjusted net income (loss) 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 certain 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. The definition of these measures may vary among companies, and, therefore, the amounts presented may not be comparable to similarly titled measures of other companies.

Bill Barrett Corporation Logo (PRNewsFoto/Bill Barrett Corporation)

 

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SOURCE Bill Barrett Corporation

Larry C. Busnardo, Vice President, Investor Relations, 303-312-8514