DENVER, March 2, 2017
/PRNewswire/ --
- Production sales volumes of 6.1 million barrels of oil
equivalent ("MMBoe") in 2016 were at the mid-point of guidance
range; represents pro forma growth of 11% over 2015
- Capital expenditures of $98
million in 2016 were below guidance range
- Lease operating expense ("LOE") of $4.58 per Boe in 2016, represents 29% improvement
compared to 2015; Denver-Julesburg ("DJ") Basin LOE of $3.41 per Boe in 2016, represents 27% improvement
compared to 2015
- DJ Basin oil price differential averaged $3.45 per barrel in 2016; represents 58%
improvement compared to 2015
- XRL drilling days have averaged 7.4 days; represents a 33%
improvement over 2015
- Recently closed bolt-on transactions for 13,800 net acres in
the DJ Basin
- Entered 2017 with $276 million of
cash and an undrawn credit facility of $300
million
- 2017 operating plan has projected capital expenditures of
$255-$285 million and production
sales volumes of 6.0-6.5 MMBoe; representing growth of 7% at the
mid-point pro forma for asset sales
- 2018 production sales volumes anticipated to be 30%-50% greater
than 2017
Bill Barrett Corporation (the "Company") (NYSE: BBG) today
reported fourth quarter and full year 2016 financial and operating
results, provided 2017 operating guidance and establishes initial
2018 production growth outlook.
For the fourth quarter of 2016, the Company reported a net loss
of $49 million, or $0.79 per diluted share. Adjusted net income
(non-GAAP) for the fourth quarter of 2016 was a net loss of
$11 million, or $0.18 per diluted share. EBITDAX for the fourth
quarter of 2016 was $46 million. For
2016, the Company reported a net loss of $170 million, or $3.08 per diluted share. Adjusted net income
(non-GAAP) for 2016 was a net loss of $38
million, or $0.68 per diluted
share. EBITDAX for 2016 was $182
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.
Chief Executive Officer and President Scot Woodall commented, "Despite a challenging
year of lower oil prices, we did an excellent job of managing
through the downturn and executing on our financial and operational
goals. Focusing on the items within our control allowed us to
report solid results for 2016, with the key drivers being
production above our initial guidance expectations, capital
spending coming in lower than anticipated, and LOE and G&A that
were both significantly lower. We also meaningfully improved our DJ
Basin oil price differentials, which helped us achieve best in
class operating margins relative to our peers."
"Based on current well cost assumptions, our XRL drilling
program generates attractive economic returns in the current
commodity price environment. Accordingly, we are adding a second
drilling rig to accelerate development and position us for
increased production growth and stronger cash flows in the future.
We are incorporating enhanced drilling and completion concepts that
we believe will translate into improved well performance and
recovery going forward. Our priority for this year is to maintain
flexibility with respect to our balance sheet as we entered 2017
with $276 million of cash, an undrawn
credit facility, and a strong underlying hedge position."
Mr. Woodall continued, "We plan to efficiently allocate capital
to our asset portfolio, while managing our liquidity and financial
flexibility. Our 2017 capital budget of $255-$285 million incorporates the addition of a
drilling rig during the second quarter and will be funded with
operating cash flow and cash on hand and we will maintain an
undrawn credit facility. This will result in annual production
growth of approximately 7% at the mid-point, pro forma for asset
divestitures. The increased activity translates into very strong
production growth for 2018 that is anticipated to be 30%-50% higher
than 2017, with a greater increase in oil volumes."
OPERATING AND FINANCIAL RESULTS
Proved Reserves
Total estimated proved reserves at year-end 2016 were 54.9 MMBoe
compared to 83.7 MMBoe at year-end 2015. Estimated proved reserves
were 57% oil, 23% natural gas and 20% natural gas liquids ("NGLs")
and were 66% developed compared to 48% developed at year-end 2015.
The decrease in estimated proved reserves compared to year-end 2015
is primarily the result of negative commodity price-related and
other revisions totaling 30.4 MMBoe, offset in part by extensions
and discoveries of 9.7 MMBoe. The Company elected to take a
conservative approach to proved undeveloped ("PUD") reserve
bookings based on the reduced development activity level that was
employed during 2016. Revisions include approximately 24.3 MMBoe
that were removed from the PUD reserves category as they are not
included in near-term development plans. Of the 24.3 MMBoe
revision, 18.2 MMBoe in the DJ Basin was removed because they would
"age out" according to the SEC's five-year development window,
which is based on when the PUD was added. Other than the timing of
development, these locations technically meet the SEC PUD
definition and could be added if the Company's future development
plan were to be accelerated. Additionally, 6.1 MMBoe of Uinta Oil
Program ("UOP") reserves were removed due to the Company electing
to not develop these locations in the current business plan. Had
these locations not been removed, the Company and its third-party
engineers estimate that year-end 2016 proved reserves would have
increased 8% compared to 2015, pro forma for asset sales. It is
anticipated that with a more active development program than was
employed during 2016, the Company will add back additional PUD
locations during 2017.
Changes in Proved
Reserves (MMBoe)
|
Proved reserves as of
December 31, 2015
|
83.7
|
|
Extensions and
discoveries
|
9.7
|
|
Production
|
(6.1)
|
|
Sale of
properties
|
(2.0)
|
|
Pricing revisions and
other
|
(30.4)
|
|
Proved reserves as of
December 31, 2016
|
54.9
|
|
2016 Production and Financial Results
Oil, natural gas and natural gas liquids production totaled 6.1
MMBoe for 2016 and was at the mid-point of the Company's guidance
range of 6.0-6.2 MMBoe. Removing volumes associated with completed
asset sales, production sales volumes totaled 5.8 MMBoe for 2016
and were approximately 11% higher compared to 2015.
Production sales volumes for the fourth quarter of 2016 totaled
1.6 MMBoe, an 8% decrease from the fourth quarter of 2015. Lower
volumes were primarily the result of non-core asset divestitures
completed during 2016 and the Company's decision to curtail
drilling for a portion of 2016 in response to a low commodity price
environment, which resulted in no new wells being placed on
production during the second half of 2016. Adjusting for production
sales volumes associated with asset sales, fourth quarter of 2016
production sales volumes were approximately 8% higher compared to
the fourth quarter of 2015.
Production sales volumes for the fourth quarter of 2016 were
weighted 62% oil, 20% natural gas and 18% NGLs. Fourth quarter
sales volumes had a slightly higher natural gas and NGL component
than previous quarters as a result of no new XRL wells being placed
on production during the second half of 2016. This is primarily due
to XRL wells having a higher percentage of oil production at the
beginning of the production cycle.
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Production
Data:
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
960
|
|
|
1,090
|
|
|
3,885
|
|
|
4,401
|
|
Natural gas
(MMcf)
|
1,866
|
|
|
1,986
|
|
|
7,170
|
|
|
7,764
|
|
NGLs
(MBbls)
|
279
|
|
|
264
|
|
|
1,010
|
|
|
898
|
|
Combined volumes
(MBoe)
|
1,550
|
|
|
1,685
|
|
|
6,090
|
|
|
6,593
|
|
Daily combined
volumes (Boe/d)
|
16,848
|
|
|
18,315
|
|
|
16,639
|
|
|
18,063
|
|
Pre-hedge commodity prices for 2016 were lower compared to
full-year 2015 as oil and natural gas prices declined significantly
during early 2016. West Texas Intermediate ("WTI") oil prices
averaged $43.32 per barrel in 2016
compared to $48.80 per barrel in
2015. NYMEX natural gas prices averaged $2.45 per MMBtu in 2016 as compared to
$2.67 per MMBtu in 2015.
For the fourth quarter of 2016, WTI oil prices averaged
$49.29 per barrel, NWPL natural gas
prices averaged $2.72 per MMBtu and
NYMEX natural gas prices averaged $2.99 per MMBtu. Fourth quarter of 2016 commodity
price differentials to benchmark pricing were: oil less
$4.53 price per barrel versus WTI;
and natural gas less $0.25 per Mcf
compared to NWPL. The DJ Basin oil price differential averaged
$3.67 per barrel as the Company
benefits from having no long-term oil marketing agreements. The NGL
price averaged approximately 33% of the WTI price per barrel.
For the fourth quarter of 2016, the Company had derivative
commodity swaps in place for 7,750 barrels of oil per day tied to
WTI pricing at $72.57 per barrel,
5,000 MMBtu of natural gas per day tied to NWPL regional pricing at
$4.10 per MMBtu and no hedges in
place for NGLs.
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Average Sales Prices
(before the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
44.76
|
|
|
$
|
35.57
|
|
|
$
|
38.83
|
|
|
$
|
40.06
|
|
Natural gas (per
Mcf)
|
2.47
|
|
|
1.98
|
|
|
1.98
|
|
|
2.23
|
|
NGLs (per
Bbl)
|
16.04
|
|
|
11.98
|
|
|
13.15
|
|
|
12.16
|
|
Combined (per
Boe)
|
33.57
|
|
|
27.21
|
|
|
29.28
|
|
|
31.02
|
|
|
|
|
|
|
|
|
|
Average Realized
Sales Prices (after the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
62.03
|
|
|
$
|
78.98
|
|
|
$
|
62.56
|
|
|
$
|
78.19
|
|
Natural gas (per
Mcf)
|
2.80
|
|
|
3.72
|
|
|
2.46
|
|
|
3.75
|
|
NGLs (per
Bbl)
|
16.04
|
|
|
11.98
|
|
|
13.15
|
|
|
12.16
|
|
Combined (per
Boe)
|
44.65
|
|
|
57.36
|
|
|
44.98
|
|
|
58.27
|
|
Cash operating costs (LOE, gathering, transportation and
processing costs, and production tax expense) totaled $6.37 per Boe in the fourth quarter of 2016 as
compared to $6.54 per Boe in the
fourth quarter of 2015.
LOE was $3.73 per Boe in the
fourth quarter of 2016 compared to $3.06 per Boe in the third quarter of 2016 and
$4.70 per Boe in the fourth quarter
of 2015. The sequential increase in LOE was anticipated due to
greater seasonal operating costs that are typically experienced
during colder months, while the year-over-year improvement was
primarily a result of improved operational efficiencies and lease
operating cost reductions in both the DJ Basin and the Uinta Oil
Program ("UOP").
DJ Basin LOE improved to $2.96 per
Boe in the fourth quarter of 2016 compared to $3.25 per Boe in the fourth quarter of 2015, and
was $3.41 per Boe in 2016 compared to
$4.64 per Boe in 2015.
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Average Costs (per
Boe):
|
|
|
|
|
|
|
|
Lease operating
expenses
|
$
|
3.73
|
|
|
$
|
4.70
|
|
|
$
|
4.58
|
|
|
$
|
6.48
|
|
Gathering,
transportation and processing expense
|
0.32
|
|
|
0.55
|
|
|
0.39
|
|
|
0.53
|
|
Production tax
expenses
|
2.32
|
|
|
1.29
|
|
|
1.75
|
|
|
1.85
|
|
Depreciation,
depletion and amortization
|
29.76
|
|
|
27.06
|
|
|
28.18
|
|
|
31.14
|
|
General and
administrative expense
|
6.86
|
|
|
8.82
|
|
|
6.92
|
|
|
8.17
|
|
The following table summarizes certain operating and financial
results for the fourth quarter of 2016 and 2015 and the years ended
2016 and 2015:
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Combined production
sales volumes (MBoe)
|
1,550
|
|
|
1,685
|
|
|
6,090
|
|
|
6,593
|
|
Net cash provided by
(used in) operating activities ($ millions)
|
$
|
5.5
|
|
|
$
|
27.8
|
|
|
$
|
121.7
|
|
|
$
|
193.7
|
|
Discretionary cash
flow ($ millions) (1)
|
$
|
32.4
|
|
|
$
|
53.3
|
|
|
$
|
126.1
|
|
|
$
|
206.3
|
|
Net income (loss) ($
millions)
|
$
|
(49.3)
|
|
|
$
|
(21.1)
|
|
|
$
|
(170.4)
|
|
|
$
|
(487.8)
|
|
Per share,
basic
|
$
|
(0.79)
|
|
|
$
|
(0.45)
|
|
|
$
|
(3.08)
|
|
|
$
|
(10.10)
|
|
Per share,
diluted
|
$
|
(0.79)
|
|
|
$
|
(0.45)
|
|
|
$
|
(3.08)
|
|
|
$
|
(10.10)
|
|
Adjusted net income
(loss) ($ millions) (1)
|
$
|
(11.2)
|
|
|
$
|
3.4
|
|
|
$
|
(37.8)
|
|
|
$
|
(9.4)
|
|
Per share,
basic
|
$
|
(0.18)
|
|
|
$
|
0.07
|
|
|
$
|
(0.68)
|
|
|
$
|
(0.20)
|
|
Per share,
diluted
|
$
|
(0.18)
|
|
|
$
|
0.07
|
|
|
$
|
(0.68)
|
|
|
$
|
(0.20)
|
|
Weighted average
shares outstanding, basic (in thousands)
|
62,241
|
|
|
48,373
|
|
|
55,384
|
|
|
48,303
|
|
Weighted average
shares outstanding, diluted (in thousands)
|
62,241
|
|
|
48,373
|
|
|
55,384
|
|
|
48,303
|
|
EBITDAX ($ millions)
(1)
|
$
|
45.8
|
|
|
$
|
68.3
|
|
|
$
|
182.4
|
|
|
$
|
266.2
|
|
|
|
(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, 2016, 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 $718.2 million and cash and cash equivalents were
$275.8 million, resulting in net debt
(principal balance of debt outstanding less the cash and cash
equivalents balance) of $442.4
million. Cash and cash equivalents include approximately
$110 million of net proceeds from the
common stock offering completed in December
2016.
DJ Basin Acquisition
The Company recently closed a transaction to acquire
approximately 13,000 net acres in the DJ Basin for $11.8
million. The acquired acreage extends southwest of the Company's
current NE Wattenberg acreage position, including its six 1,280
acre "south of the river" DSUs currently under development. It is
estimated that the acquired acreage contains approximately 80
operated XRL drilling locations and additional ownership in
approximately 20 gross XRL locations, which are all prospective for
the Niobrara "B", Niobrara "C" and Codell horizons.
In addition, the Company was the successful bidder on five lease
parcels at the November 2016,
Colorado state lease sale,
comprising 830 acres, for bonus bids totaling approximately
$1.5 million.
Capital Expenditures
Capital expenditures of $98.3
million for 2016 were 66% lower than 2015 and included
drilling 15 net operated XRL wells in the DJ Basin. Capital
expenditures included $86.3 million
for drilling and completion operations, $5.6
million for leaseholds to expand development programs, and
$6.4 million for infrastructure and
corporate purposes.
Capital expenditures for the fourth quarter of 2016 totaled
$28.8 million and included drilling
11 net operated XRL wells in the DJ Basin. Capital expenditures
included $25.5 million for drilling
and completion operations, $3.0
million for leaseholds, and $0.3
million for infrastructure and corporate assets.
|
Three Months Ended
December 31, 2016
|
|
Twelve Months
Ended December 31, 2016
|
|
Average Net
Daily
Production
(Boe/d)
|
|
Operated
Wells
Drilled (Net)
|
|
Capital
Expenditures
($ millions)
|
|
Average Net
Daily
Production
(Boe/d)
|
|
Operated
Wells
Drilled (Net)
|
|
Capital
Expenditures
($ millions)
|
Basin:
|
|
|
|
|
|
|
|
|
|
|
|
Denver-Julesburg
|
14,826
|
|
|
11
|
|
$
|
28.5
|
|
|
13,809
|
|
|
15
|
|
$
|
95.5
|
|
Uinta
|
2,000
|
|
|
—
|
|
0.3
|
|
|
2,792
|
|
|
—
|
|
1.4
|
|
Other
|
22
|
|
|
—
|
|
—
|
|
|
38
|
|
|
—
|
|
1.4
|
|
Total
|
16,848
|
|
|
11
|
|
$
|
28.8
|
|
|
16,639
|
|
|
15
|
|
$
|
98.3
|
|
OPERATIONAL HIGHLIGHTS
DJ Basin
In the fourth quarter of 2016, the Company produced an average
of 14,826 Boe/d, which was a 15% increase from the fourth quarter
of 2015 average of 12,864 Boe/d, excluding volumes associated with
asset sales. DJ Basin oil volumes averaged 8,723 Bbls/d, which was
an increase of 13% from the fourth quarter of 2015, excluding
volumes associated with asset sales.
The Company resumed drilling operations during the third quarter
of 2016 with the initial DSU being recently placed on initial
flowback. Accordingly, the Company did not have any new wells on
production during the fourth quarter of 2016. The Company is
currently operating one drilling rig in NE Wattenberg and plans to
add a rig to accelerate development during the second quarter of
2017.
The following provides a synopsis of the current DSU
activity:
-
- 4-62-20 - the DSU is located within the southern area of
NE Wattenberg and includes 4 XRL wells. The wells incorporated
increased proppant of up to 1,350 pounds of sand per lateral foot.
The wells were placed on initial flowback in February 2017 and are connected to pipeline
infrastructure that the Company constructed beneath the South
Platte River in 2016. The infrastructure allows for the future
development of the Company's acreage located south of the
river.
- 5-62-27 - the DSU is located within the central area of
NE Wattenberg and includes 9 XRL wells. Completion operations have
commenced and it is expected that the wells will be placed on
initial flowback during the second quarter of 2017. This DSU
includes a combination of wells that incorporated enhanced proppant
loading of approximately 1,500 pounds of sand per lateral foot and
monobores.
- 6-62-10 - the Company has drilled a DSU which is located
within the northern area of NE Wattenberg that includes 4 XRL
wells. Based on lease configuration, an additional 10 mid-reach
lateral wells are being drilled to develop the DSU. It is expected
that the wells will be completed in second quarter of 2017 and
placed on initial flowback during the third quarter of 2017. The
wells will incorporate enhanced proppant loading of up to 1,500
pounds of sand per lateral foot and additional frac stages.
- Since resuming drilling operations in September 2016, XRL well drilling days to rig
release have averaged approximately 7.4 days per well, including a
best-in-class well that was drilled in approximately 5.6 days. This
represents a 33% improvement from the average of 2015.
- Drilling and completion costs for the most recent XRL wells
have averaged approximately $4.25
million per well, which includes the cost of incorporating
higher proppant concentrations.
Uinta Oil Program
The Company produced an average of 2,000 Boe/d for the fourth
quarter of 2016. There was no new drilling and completion activity
in the UOP during the fourth quarter of 2016. Future operations
consist of several planned recompletions during the second quarter
of 2017.
2017 OPERATING GUIDANCE
The 2017 capital program is designed to maintain financial and
operational flexibility, while accelerating development in NE
Wattenberg. Accordingly, an additional drilling rig will be added
during the second quarter of 2017. The capital program will
primarily be focused on XRL well development in the DJ Basin with
expenditures in the UOP consisting of planned well recompletions
during the second quarter of 2017. Based on the forecasted timing
of completions associated with the second drilling rig, the
increased activity is expected to contribute minimally to 2017
production, but is expected to have a greater impact in 2018. It is
expected that 2017 production levels will be approximately 7%
higher than 2016 production at the mid-point of guidance, pro forma
for previously completed asset sales, with 2018 corporate
production anticipated to grow 30%-50%.
The Company enters 2017 well positioned having ample liquidity,
a strong underlying hedge position with 60%-65% of its 2017 oil
production currently hedged at an average of $58.47 per barrel of oil, nominal drilling
commitments and no long-term drilling, completion or oil marketing
contracts. As such, the Company retains the operational and
financial flexibility to accelerate or decelerate development
activity in response to any changes in economic conditions. The
capital expenditure program is expected to be funded with operating
cash flow and available cash on hand. The Company also expects to
exit 2017 with a positive cash position and an undrawn credit
facility.
The Company is providing the following guidance for its 2017
activities. See "Forward-Looking Statements" below.
- Capital expenditures of approximately $255-$285 million
- Assumes the addition of a second drilling rig in the second
quarter.
- Approximately 70-75 gross XRL wells are expected to be drilled
in the NE Wattenberg field of the DJ Basin.
- XRL well costs are expected to average approximately
$4.75 million per well; reflecting
enhanced completion designs and potential increases in service
costs, partially offset by additional drilling efficiencies.
- First quarter of 2017 capital expenditures are expected to be
approximately $60-$65 million, which
includes approximately $12 million
for the portion of the aforementioned DJ Basin acreage acquisition
that closed in 2017.
- Production of 6.0-6.5 MMBoe
- Represents a production level that is approximately 7% higher
at the mid-point than pro forma 2016 production sales volumes of
5.8 MMBoe, excluding assets divested in 2016.
- Production is estimated to be approximately 60-65% oil, 20%
natural gas and 15-20% NGLs.
- First quarter of 2017 production is expected to approximate
1.35-1.45 MMBoe, which represents lower sequential production from
the fourth quarter of 2016, in part, due to no new wells being
placed on production during the fourth quarter of 2016 and the
timing of wells being placed on flowback during the first quarter
of 2017.
- Lease operating expense of $27-$30
million
- Cash general and administrative expense of $30-$33 million
- Gathering, transportation and processing costs of $2-$3 million
- Unused commitment for firm natural gas transportation charges
of $18-$19 million
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 2017, 6,846 barrels per day of oil is hedged at an average
WTI price of $58.47 per barrel and
10,000 MMBtu/d of natural gas is hedged at an average NWPL price of
$2.96 per MMBtu.
For 2018, 2,616 barrels per day of oil is hedged at an average
WTI price of $55.00 per barrel and no
natural gas hedges in place.
As of March 2, 2017, the Company
had the following commodity hedge positions in place for 2017 and
2018:
|
|
Oil
(WTI)
|
|
Natural Gas
(NWPL)
|
Period
|
|
Volume
Bbls/d
|
|
Price
$/Bbl
|
|
Volume
MMBtu/d
|
|
Price
$/MMBtu
|
1Q17
|
|
6,500
|
|
|
$
|
58.20
|
|
|
10,000
|
|
|
$
|
2.96
|
|
2Q17
|
|
6,625
|
|
|
58.10
|
|
|
10,000
|
|
|
2.96
|
|
3Q17
|
|
7,125
|
|
|
58.77
|
|
|
10,000
|
|
|
2.96
|
|
4Q17
|
|
7,125
|
|
|
58.77
|
|
|
10,000
|
|
|
2.96
|
|
1Q18
|
|
3,750
|
|
|
54.97
|
|
|
—
|
|
|
—
|
|
2Q18
|
|
3,750
|
|
|
54.97
|
|
|
—
|
|
|
—
|
|
3Q18
|
|
1,500
|
|
|
55.06
|
|
|
—
|
|
|
—
|
|
4Q18
|
|
1,500
|
|
|
55.06
|
|
|
—
|
|
|
—
|
|
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 Friday,
March 3, 2017, 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 60765706. The webcast will remain on the Company's
website for approximately 30 days and a replay of the call will be
available through Friday, March 10, 2017 at 855-859-2056
(404-537-3406 international) with passcode 60765706.
For additional information, reference the Fourth Quarter and
Full-Year 2016 Results presentation that will be available on the
Investor Relations page of the Company's website prior to the start
of the conference call.
Investor Events
Members of management are scheduled to participate in the
following investor events:
- March 16, 2017 - Wells Fargo
Securities High Yield group meeting in Denver, CO
- March 27, 2017 - Scotia Howard
Weil Energy Conference in New Orleans,
LA
Presentation materials for the conference will be posted to the
Company's website at www.billbarrettcorp.com in the Investor
Relations section.
DISCLOSURE STATEMENTS
Reserve Disclosure
The Company may from time to time provide internally generated
estimates of its probable and possible reserves. These
estimates conform to SPEE methodology, but are not prepared or
reviewed by third party engineers. Unless otherwise indicated,
probable and possible reserve estimates are determined using
year-end pricing, as used in the calculation of proved reserves.
Probable and possible reserves are subject to significantly greater
risk of recovery than proved reserves.
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 of 1933 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
"2017 Operating Guidance," which contains projections for certain
2017 operational and financial metrics, and an outlook for 2018
production. Additional forward-looking statements in this release
relate to, among other things, future capital expenditures,
projects, rates of return, 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 or unfavorable purchase price
adjustments; title to properties; litigation; and environmental
liabilities. Please refer to the Company's Annual Report on Form
10-K for the year ended December 31, 2015 filed with the SEC
and for the year 2016 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 to not 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,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Production
Data:
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
960
|
|
|
1,090
|
|
|
3,885
|
|
|
4,401
|
|
Natural gas
(MMcf)
|
1,866
|
|
|
1,986
|
|
|
7,170
|
|
|
7,764
|
|
NGLs
(MBbls)
|
279
|
|
|
264
|
|
|
1,010
|
|
|
898
|
|
Combined volumes
(MBoe)
|
1,550
|
|
|
1,685
|
|
|
6,090
|
|
|
6,593
|
|
Daily combined
volumes (Boe/d)
|
16,848
|
|
|
18,315
|
|
|
16,639
|
|
|
18,063
|
|
|
|
|
|
|
|
|
|
Average Sales Prices
(before the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
44.76
|
|
|
$
|
35.57
|
|
|
$
|
38.83
|
|
|
$
|
40.06
|
|
Natural gas (per
Mcf)
|
2.47
|
|
|
1.98
|
|
|
1.98
|
|
|
2.23
|
|
NGLs (per
Bbl)
|
16.04
|
|
|
11.98
|
|
|
13.15
|
|
|
12.16
|
|
Combined (per
Boe)
|
33.57
|
|
|
27.21
|
|
|
29.28
|
|
|
31.02
|
|
|
|
|
|
|
|
|
|
Average Realized
Sales Prices (after the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
62.03
|
|
|
$
|
78.98
|
|
|
$
|
62.56
|
|
|
$
|
78.19
|
|
Natural gas (per
Mcf)
|
2.80
|
|
|
3.72
|
|
|
2.46
|
|
|
3.75
|
|
NGLs (per
Bbl)
|
16.04
|
|
|
11.98
|
|
|
13.15
|
|
|
12.16
|
|
Combined (per
Boe)
|
44.65
|
|
|
57.36
|
|
|
44.98
|
|
|
58.27
|
|
|
|
|
|
|
|
|
|
Average Costs (per
Boe):
|
|
|
|
|
|
|
|
Lease operating
expenses
|
$
|
3.73
|
|
|
$
|
4.70
|
|
|
$
|
4.58
|
|
|
$
|
6.48
|
|
Gathering,
transportation and processing expense
|
0.32
|
|
|
0.55
|
|
|
0.39
|
|
|
0.53
|
|
Production tax
expenses
|
2.32
|
|
|
1.29
|
|
|
1.75
|
|
|
1.85
|
|
Depreciation,
depletion and amortization
|
29.76
|
|
|
27.06
|
|
|
28.18
|
|
|
31.14
|
|
General and
administrative expense (1)
|
6.86
|
|
|
8.82
|
|
|
6.92
|
|
|
8.17
|
|
|
|
(1)
|
Includes long-term
cash and equity incentive compensation of $2.12 per Boe and $1.79
per Boe for the three months ended December 31, 2016 and 2015,
respectively, and $1.96 per Boe and $1.64 per Boe for the twelve
months ended December 31, 2016 and 2015, respectively.
|
BILL BARRETT
CORPORATION Consolidated Condensed Balance
Sheets (Unaudited)
|
|
|
As of
December 31,
|
|
As
of
December
31,
|
|
2016
|
|
2015
|
|
(in
thousands)
|
Assets:
|
|
|
|
Cash and cash
equivalents
|
$
|
275,841
|
|
|
$
|
128,836
|
|
Other current assets
(1)
|
42,611
|
|
|
145,481
|
|
Property and
equipment, net
|
1,062,149
|
|
|
1,170,684
|
|
Other noncurrent
assets
|
4,740
|
|
|
61,519
|
|
Total
assets
|
$
|
1,385,341
|
|
|
$
|
1,506,520
|
|
|
|
|
|
Liabilities and
Stockholders' Equity:
|
|
|
|
Current liabilities
(1)
|
$
|
85,018
|
|
|
$
|
145,231
|
|
Long-term debt, net
of debt issuance costs
|
711,808
|
|
|
794,652
|
|
Other long-term
liabilities (1)
|
16,972
|
|
|
17,221
|
|
Stockholders'
equity
|
571,543
|
|
|
549,416
|
|
Total liabilities and
stockholders' equity
|
$
|
1,385,341
|
|
|
$
|
1,506,520
|
|
|
|
(1)
|
At December 31,
2016, the estimated fair value of all of the Company's commodity
derivative instruments was a net asset of $3.2 million, comprised
of $8.4 million of current assets, $4.3 million of current
liabilities and $0.9 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,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in thousands,
except per share amounts)
|
Operating
Revenues:
|
|
|
|
|
|
|
|
Oil, gas and
NGLs
|
$
|
52,049
|
|
|
$
|
45,870
|
|
|
$
|
178,328
|
|
|
$
|
204,537
|
|
Other operating
revenues
|
(429)
|
|
|
691
|
|
|
491
|
|
|
3,355
|
|
Total operating
revenues
|
51,620
|
|
|
46,561
|
|
|
178,819
|
|
|
207,892
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
Lease
operating
|
5,785
|
|
|
7,919
|
|
|
27,886
|
|
|
42,753
|
|
Gathering,
transportation and processing
|
494
|
|
|
923
|
|
|
2,365
|
|
|
3,482
|
|
Production
tax
|
3,601
|
|
|
2,177
|
|
|
10,638
|
|
|
12,197
|
|
Exploration
|
19
|
|
|
8
|
|
|
83
|
|
|
153
|
|
Impairment, dry hole
costs and abandonment
|
2,483
|
|
|
314
|
|
|
4,249
|
|
|
575,310
|
|
(Gain) loss on sale
of properties
|
(128)
|
|
|
2,504
|
|
|
1,078
|
|
|
1,745
|
|
Depreciation,
depletion and amortization
|
46,150
|
|
|
45,609
|
|
|
171,641
|
|
|
205,275
|
|
Unused
commitments
|
4,569
|
|
|
5,936
|
|
|
18,272
|
|
|
19,099
|
|
General and
administrative (1)
|
10,634
|
|
|
14,864
|
|
|
42,169
|
|
|
53,890
|
|
Other operating
expenses, net
|
(316)
|
|
|
—
|
|
|
(316)
|
|
|
—
|
|
Total operating
expenses
|
73,291
|
|
|
80,254
|
|
|
278,065
|
|
|
913,904
|
|
Operating Income
(Loss)
|
(21,671)
|
|
|
(33,693)
|
|
|
(99,246)
|
|
|
(706,012)
|
|
Other Income and
Expense:
|
|
|
|
|
|
|
|
Interest and other
income
|
69
|
|
|
46
|
|
|
235
|
|
|
565
|
|
Interest
expense
|
(14,213)
|
|
|
(15,731)
|
|
|
(59,373)
|
|
|
(65,305)
|
|
Commodity derivative
gain (loss) (2)
|
(13,462)
|
|
|
28,233
|
|
|
(20,720)
|
|
|
104,147
|
|
Gain (loss) on
extinguishment of debt
|
—
|
|
|
—
|
|
|
8,726
|
|
|
1,749
|
|
Total other income
and expense
|
(27,606)
|
|
|
12,548
|
|
|
(71,132)
|
|
|
41,156
|
|
Income (Loss) before
Income Taxes
|
(49,277)
|
|
|
(21,145)
|
|
|
(170,378)
|
|
|
(664,856)
|
|
(Provision for)
Benefit from Income Taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
177,085
|
|
Net Income
(Loss)
|
$
|
(49,277)
|
|
|
$
|
(21,145)
|
|
|
$
|
(170,378)
|
|
|
$
|
(487,771)
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) per
Common Share
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.79)
|
|
|
$
|
(0.45)
|
|
|
$
|
(3.08)
|
|
|
$
|
(10.10)
|
|
Diluted
|
$
|
(0.79)
|
|
|
$
|
(0.45)
|
|
|
$
|
(3.08)
|
|
|
$
|
(10.10)
|
|
Weighted Average
Common Shares Outstanding
|
|
|
|
|
|
|
|
Basic
|
62,241
|
|
|
48,373
|
|
|
55,384
|
|
|
48,303
|
|
Diluted
|
62,241
|
|
|
48,373
|
|
|
55,384
|
|
|
48,303
|
|
|
|
(1)
|
Includes long-term
cash and equity incentive compensation of $3.3 million and $3.0
million for the three months ended December 31, 2016 and 2015,
respectively, and $11.9 million and $10.8 million for the twelve
months ended December 31, 2016 and 2015, 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,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in
thousands)
|
Included in commodity
derivative gain (loss):
|
|
|
|
|
|
|
|
Realized gain (loss)
on derivatives
|
$
|
17,181
|
|
|
$
|
50,818
|
|
|
$
|
95,598
|
|
|
$
|
179,652
|
|
Reversal of prior
year unrealized gain transferred to realized gain
|
(20,754)
|
|
|
(46,681)
|
|
|
(99,809)
|
|
|
(145,226)
|
|
Unrealized gain
(loss) on derivatives
|
(9,889)
|
|
|
24,096
|
|
|
(16,509)
|
|
|
69,721
|
|
Total commodity
derivative gain (loss)
|
$
|
(13,462)
|
|
|
$
|
28,233
|
|
|
$
|
(20,720)
|
|
|
$
|
104,147
|
|
BILL BARRETT
CORPORATION Consolidated Statements of Cash
Flows (Unaudited)
|
|
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in
thousands)
|
Operating
Activities:
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
|
(49,277)
|
|
|
$
|
(21,145)
|
|
|
$
|
(170,378)
|
|
|
$
|
(487,771)
|
|
Adjustments to
reconcile to net cash provided by operations:
|
Depreciation,
depletion and amortization
|
46,150
|
|
|
45,609
|
|
|
171,641
|
|
|
205,275
|
|
Impairment, dry hole
costs and abandonment expense
|
2,483
|
|
|
314
|
|
|
4,249
|
|
|
575,310
|
|
Unrealized derivative
(gain) loss
|
30,643
|
|
|
22,585
|
|
|
116,318
|
|
|
75,505
|
|
Deferred income tax
benefit
|
—
|
|
|
—
|
|
|
—
|
|
|
(176,797)
|
|
Incentive
compensation and other non-cash charges
|
1,774
|
|
|
2,759
|
|
|
8,982
|
|
|
10,040
|
|
Amortization of debt
discounts and deferred financing costs
|
759
|
|
|
641
|
|
|
2,834
|
|
|
4,624
|
|
(Gain) loss on sale
of properties
|
(128)
|
|
|
2,504
|
|
|
1,078
|
|
|
1,745
|
|
(Gain) loss on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(8,726)
|
|
|
(1,749)
|
|
Change in operating
assets and liabilities:
|
|
|
|
|
|
|
|
Accounts
receivable
|
(2,928)
|
|
|
601
|
|
|
10,624
|
|
|
20,995
|
|
Prepayments and other
assets
|
1,318
|
|
|
572
|
|
|
350
|
|
|
311
|
|
Accounts payable,
accrued and other liabilities
|
(21,796)
|
|
|
(23,145)
|
|
|
(2,893)
|
|
|
(18,798)
|
|
Amounts payable to
oil and gas property owners
|
(6,571)
|
|
|
(2,680)
|
|
|
(9,465)
|
|
|
(3,530)
|
|
Production taxes
payable
|
3,102
|
|
|
(838)
|
|
|
(2,878)
|
|
|
(11,482)
|
|
Net cash provided by
(used in) operating activities
|
$
|
5,529
|
|
|
$
|
27,777
|
|
|
$
|
121,736
|
|
|
$
|
193,678
|
|
Investing
Activities:
|
|
|
|
|
|
|
|
Additions to oil and
gas properties, including acquisitions
|
(13,166)
|
|
|
(68,475)
|
|
|
(106,870)
|
|
|
(324,534)
|
|
Additions of
furniture, equipment and other
|
(11)
|
|
|
(187)
|
|
|
(1,195)
|
|
|
(1,223)
|
|
Proceeds from sale of
properties and other investing activities
|
(644)
|
|
|
56,505
|
|
|
24,927
|
|
|
123,122
|
|
Proceeds from the
sale of short-term investments
|
—
|
|
|
20,000
|
|
|
—
|
|
|
115,000
|
|
Cash paid for
short-term investments
|
—
|
|
|
—
|
|
|
—
|
|
|
(114,883)
|
|
Net cash
provided by (used in) investing activities
|
$
|
(13,821)
|
|
|
$
|
7,843
|
|
|
$
|
(83,138)
|
|
|
$
|
(202,518)
|
|
Financing
Activities:
|
|
|
|
|
|
|
|
Principal payments on
debt
|
(111)
|
|
|
(108)
|
|
|
(440)
|
|
|
(25,191)
|
|
Deferred financing
costs and other
|
(21)
|
|
|
488
|
|
|
(1,156)
|
|
|
(3,037)
|
|
Proceeds from sale of
common stock
|
110,002
|
|
|
—
|
|
|
110,003
|
|
|
—
|
|
Net cash provided by
(used in) financing activities
|
$
|
109,870
|
|
|
$
|
380
|
|
|
$
|
108,407
|
|
|
$
|
(28,228)
|
|
Increase (Decrease)
in Cash and Cash Equivalents
|
101,578
|
|
|
36,000
|
|
|
147,005
|
|
|
(37,068)
|
|
Beginning Cash and
Cash Equivalents
|
174,263
|
|
|
92,836
|
|
|
128,836
|
|
|
165,904
|
|
Ending Cash and Cash
Equivalents
|
$
|
275,841
|
|
|
$
|
128,836
|
|
|
$
|
275,841
|
|
|
$
|
128,836
|
|
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,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in
thousands)
|
Net Cash Provided by
(Used in) Operating Activities
|
$
|
5,529
|
|
|
$
|
27,777
|
|
|
$
|
121,736
|
|
|
$
|
193,678
|
|
Adjustments to
reconcile to discretionary cash flow:
|
|
|
|
|
|
|
|
Exploration
expense
|
19
|
|
|
8
|
|
|
83
|
|
|
153
|
|
Changes in working
capital
|
26,875
|
|
|
25,490
|
|
|
4,262
|
|
|
12,504
|
|
Discretionary Cash
Flow
|
$
|
32,423
|
|
|
$
|
53,275
|
|
|
$
|
126,081
|
|
|
$
|
206,335
|
|
Adjusted Net
Income (Loss) Reconciliation
|
|
|
|
|
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in thousands,
except per share amounts)
|
Net Income
(Loss)
|
$
|
(49,277)
|
|
|
$
|
(21,145)
|
|
|
$
|
(170,378)
|
|
|
$
|
(487,771)
|
|
Provision for
(Benefit from) income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
(177,085)
|
|
Income (Loss) before
Income Taxes
|
(49,277)
|
|
|
(21,145)
|
|
|
(170,378)
|
|
|
(664,856)
|
|
Adjustments to Net
Income (Loss):
|
|
|
|
|
|
|
|
Unrealized derivative
(gain) loss
|
30,643
|
|
|
22,585
|
|
|
116,318
|
|
|
75,505
|
|
Impairment
expense
|
—
|
|
|
72
|
|
|
183
|
|
|
572,438
|
|
(Gain) loss on sale
of properties
|
(128)
|
|
|
2,504
|
|
|
1,078
|
|
|
1,745
|
|
(Gain) loss on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(8,726)
|
|
|
(1,749)
|
|
One-time
items:
|
|
|
|
|
|
|
|
CO2 unused
commitment
|
—
|
|
|
1,429
|
|
|
—
|
|
|
1,429
|
|
West Tavaputs NGL
processing true-up
|
—
|
|
|
(268)
|
|
|
—
|
|
|
(1,273)
|
|
Expenses relating to
amending credit facility
|
—
|
|
|
—
|
|
|
—
|
|
|
1,617
|
|
(Income) expense
related to properties sold
|
576
|
|
|
—
|
|
|
576
|
|
|
—
|
|
Adjusted Income
(Loss) before Income Taxes
|
(18,186)
|
|
|
5,177
|
|
|
(60,949)
|
|
|
(15,144)
|
|
Adjusted (provision
for) benefit from income taxes (1)
|
7,003
|
|
|
(1,804)
|
|
|
23,167
|
|
|
5,714
|
|
Adjusted Net Income
(Loss)
|
$
|
(11,183)
|
|
|
$
|
3,373
|
|
|
$
|
(37,782)
|
|
|
$
|
(9,430)
|
|
Per share,
diluted
|
$
|
(0.18)
|
|
|
$
|
0.07
|
|
|
$
|
(0.68)
|
|
|
$
|
(0.20)
|
|
|
|
(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,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in
thousands)
|
Net Income
(Loss)
|
$
|
(49,277)
|
|
|
$
|
(21,145)
|
|
|
$
|
(170,378)
|
|
|
$
|
(487,771)
|
|
Adjustments to
reconcile to EBITDAX:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
46,150
|
|
|
45,609
|
|
|
171,641
|
|
|
205,275
|
|
Impairment, dry hole
and abandonment expense
|
2,483
|
|
|
314
|
|
|
4,249
|
|
|
575,310
|
|
Exploration
expense
|
19
|
|
|
8
|
|
|
83
|
|
|
153
|
|
Unrealized derivative
(gain) loss
|
30,643
|
|
|
22,585
|
|
|
116,318
|
|
|
75,505
|
|
Incentive
compensation and other non-cash charges
|
1,774
|
|
|
2,759
|
|
|
8,982
|
|
|
10,040
|
|
(Gain) loss on sale
of properties
|
(128)
|
|
|
2,504
|
|
|
1,078
|
|
|
1,745
|
|
(Gain) loss on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(8,726)
|
|
|
(1,749)
|
|
Interest and other
income
|
(69)
|
|
|
(46)
|
|
|
(235)
|
|
|
(565)
|
|
Interest
expense
|
14,213
|
|
|
15,731
|
|
|
59,373
|
|
|
65,305
|
|
Provision for
(benefit from) income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
(177,085)
|
|
EBITDAX
|
$
|
45,808
|
|
|
$
|
68,319
|
|
|
$
|
182,385
|
|
|
$
|
266,163
|
|
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.
|
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/bill-barrett-corporation-reports-fourth-quarter-and-year-end-2016-financial-and-operating-results-provides-2017-operating-guidance-and-establishes-initial-2018-production-growth-outlook-of-30-50-300417239.html
SOURCE Bill Barrett Corporation