2Q17 Production Beats June Revised Guidance
On Continued Strength of Gen 3 Results
Per-Unit LOE and SG&A Decrease
Substantially in 2Q17
Bolt-on Lease Acquisitions Expanding
Footprint, Helping Increase Inventory in Midland and Delaware
Basins
NOTE: 2Q17 conference call slides available
at www.energen.com
Energen Corporation (NYSE: EGN) (“Energen” or the “company”)
today announced financial and operating results for the second
quarter ended June 30, 2017.
FINANCIAL AND OPERATING
HIGHLIGHTS
2Q17
- Production beats June revised
guidance by 2% and May guidance by 17%
- On track to generate 29% YOY growth
in total production and 37% YOY growth in Midland and Delaware
production
- Adjusted EBITDAX grows 49% from 1Q17
and beats internal expectations
- Per-unit LOE (including marketing
and transportation) beats June revised guidance midpoint by
8.1%
- Per unit SG&A beats June revised
guidance midpoint by 10.4%
- Lease acquisitions in first six
months of 2017 total 9,732 net acres for ≈$215 mm
- Energen adds 158 net locations to
Wolfcamp/Spraberry/Cline inventory and identifies 413 net locations
in other Delaware Basin formations for total identified inventory
of 4,116 net locations
2Q17 WELL RESULTS
- 45 gross and net wells in the
Midland and Delaware basins were turned to production in 2Q17 and
generated excellent initial production rates in all key areas of
operational focus in 2017; 78% are multi-zone pattern wells
completed in batches
- 59 Gen 3 wells are outperforming the
highest EUR type curve and significantly outperforming the
midpoint EUR type curve; 76% are multi-zone pattern wells completed
in batches
- Public data shows Gen 3 wells in
Midland and Delaware basins outperforming other operators’
wells
Comments from the CEO
“The success we are achieving with our Generation 3 frac design
and multi-zone pattern wells completed in batches has set the stage
for 2017 to be the break-out year we have been working toward,
underscoring our top-tier assets and solid execution,” said Energen
Chief Executive Officer James McManus. “We are delivering
outstanding well performance in all our areas of operational focus
in the Midland and Delaware basins; and we continue to drive down
our operating costs and G&A and are competitive with the best
in the Midland and Delaware basins.
“Importantly, our Gen 3 wells are outperforming wells completed
by other operators. The public well data also supports our position
that the best way to maximize the full development of our assets is
to complete them in multi-zone batches at original reservoir
pressure,” McManus said. “We expect our Gen 3 multi-zone pattern
wells to continue driving production growth as we move forward.
“We have continued executing on our bolt-on acquisition program,
which we believe has created significant value for Energen. Over
the last 18 months, we have added approximately 19,000 net acres in
prime Delaware and Midland basin locations for an average price of
about $17,600 an acre,” McManus said. “This includes some 9,700 net
acres acquired in the first six months of this year that helped
contribute to an increase in our inventory of identified
locations.
“We are pleased with our performance this quarter and excited
about our future prospects as we successfully implement our 2017
drilling and development program. We plan to maintain our focus on
the further optimization of well performance and returns, and we
are confident that Energen is well-positioned to continue
delivering strong results and creating shareholder value in 2017
and beyond.”
Operations Update
In the second quarter of 2017, Energen turned to production 27
gross (27 net) wells in the Midland Basin and 18 gross (18 net)
wells in the Delaware Basin; 78 percent are multi-zone pattern
wells completed in batches. The company operated an average of 6.5
horizontal drilling rigs and an average of 4 frac crews. In the
first six months of 2017, Energen turned to production 49 net wells
in its 60-net well DUC inventory at year-end 2016.
2017 First Production/Flow back
(Horizontal Wells – Gross/Net)
1Q17a 2Q17a
3Q17e 4Q17e
CY17e Midland Basin 10/9 27/27
20/19 19/14 76/69
Delaware Basin 2/2 18/18
3/3 12/12 35/35
2Q17 Wells Turned to Production
Area # of Wells
AverageCompletedLateral
Length
Avg. Peak 24-Hour IP Avg. Peak 30-day
IP Boepd %Oil Boepd
%Oil
Delaware Basin 18
Wolfcamp A (8)
Wolfcamp B (10)
9,466’
2,338 59
1,8891
60
Northern Midland Basin 11
MSB (4), Jo Mill (3),LSB (4)
10,531’
1,250 88
1,2122 85
Northern
Midland Basin 8 Wolfcamp A (3)
Wolfcamp B (5)
10,510’
1,558 86
1,270 3 81
Central
Midland Basin 8
Wolfcamp A (3)
Wolfcamp B (5)
7,502’
1,671 79
1,126 66
1 16 wells with 30-day data
2 4 wells with 30-day data
3 7 wells with 30-day data
For 59 of the Gen 3 wells drilled to date (76 percent of which
were multi-zone pattern wells completed in batches), the average
cumulative production uplift of wells in each formation group
(normalized to 10,000’) is exceeding the highest EUR type curve –
and significantly outperforming the midpoint EUR type curve –
identified for wells in that group completed with pre-Gen 3 frac
designs. These are key measures of success for Energen’s latest
frac design.
Relative to the midpoint EUR type curve, the average cumulative
production uplift of the Gen 3 wells normalized to 10,000’ is:
- ≈31% over a 1.75 MMBOE type curve at
270 days for 20 Delaware Basin Wolfcamp A and B wells – 9 of 20 are
multi-zone pattern wells completed in batches
- ≈40% over a 1.2 MMBOE type curve at 90
days for 11 wells in the Spraberry package – all are multi-zone
pattern wells completed in batches
- ≈11% over a 1.2 MMBOE type curve at 240
days for 10 northern Midland Basin Wolfcamp A and B wells – 7 of 10
are multi-zone pattern wells completed in batches
- ≈21% over a 1.2 MMBOE type curve at 170
days for 16 central Midland Basin Wolfcamp A and B wells – all are
multi-zone pattern wells in batches
- ≈47% over a 850 MBOE type curve at 160
days for 2 central Midland Basin Lower Spraberry wells – both are
multi-zone pattern wells completed in batches
In another assessment of success, the average cumulative
production of Energen’s Midland Basin Gen 3 multi-zone pattern
wells completed in batches is outperforming other operators’
pattern wells; and the average cumulative production of Energen’s
Gen 3 wells (pattern and stand-alone) in the Midland and Delaware
basins is outperforming other operators’ wells with comparable
proppant loads of 1,700-2,500 pounds per foot.
The company attributes this outperformance to completing the
wells in multi-zone batches instead of completing them as offset
pattern wells. Utilizing simultaneous, multi-zone pattern
development allows all wells to be completed at the original
reservoir pressure, which should maximize reservoir productivity.
In offset pattern well development, the original stand-alone well
causes the reservoir pressure to drop and reduces the productivity
of all subsequent wells drilled.
Bolt-on Lease Acquisitions Continue,
Inventory Grows
In the first six months of 2017, Energen has acquired more than
9,700 net acres for approximately $215 million, or an average price
of some $22,000 per acre. These acquisitions helped contribute to
the addition of 158 net locations in its Wolfcamp, Spraberry, and
Cline inventory (after moving 32 net locations into the drilled
category). The company also has identified 413 net locations in
other Delaware Basin formations, giving the company a new
identified inventory of 4,116 net locations.
The company also has purchased 690 net mineral acres in the
Delaware Basin in the first six months of 2017 for approximately
$20 million.
Over the last 18 months (CY16 and YTD17), the company’s bolt-on
acquisition program has added approximately 19,000 net lease acres
in prime Delaware and Midland basin locations for an average price
of approximately $17,600 an acre.
2017 Capital Overview
Energen’s estimate of capital spending for drilling and
development in 2017 remains unchanged at $850-$900 million.
Capital Summary by Basin
2017e Capital ($MM) Midland Basin
$ 470 - 490 Delaware Basin
$ 375 - 405 Central Basin, ARO, Other
$ 5 Drilling & Development Capital
$ 850 - 900 Acquisitions/Unproved
Leasehold $ 235 Total Capital
Expenditures $ 1,085 - 1,135
Liquidity and Leverage
Update
As of June 30, 2017, Energen had cash of $0.5 million, long-term
debt of $544.7 million, and $131.5 million drawn on its $1.05
billion line of credit, and its borrowing base currently is $1.4
billion. Energen estimates that its year-end 2017 total net
debt-to-2017 adjusted EBITDAX will range from 1.3x - 1.4x.
2Q17 Financial Results
For the 3 months ended June 30, 2017, Energen reported GAAP net
income from all operations of $29.5 million, or $0.30 per diluted
share. Adjusting for a non-cash gain on mark-to-market derivatives
and a small, non-cash impairment loss, Energen had adjusted net
income in 2Q17 of $5.4 million, or $0.06 per diluted share. This
compares with an adjusted loss in 2Q16 of $(27.1 million), or
$(0.28) per diluted share. [See “Non-GAAP Financial Measures”
beginning on pp 8 for more information and reconciliation.]
Energen’s adjusted 2Q17 net income of $5.4 million exceeded
internal expectations by $1.6 million largely due to:
- Less-than-expected lease operating
expense (LOE) largely due to lower power and chemical costs;
- Higher production due to continued
positive impact of Gen 3 completions;
- Lower salaries and general and
administrative expense (SG&A) primarily due to lower non-cash
compensation; and
- Decreased production and ad valorem
taxes.
Partially offsetting these gains were lower realized sales
prices and increased depreciation, depletion, and amortization
expense (DD&A) largely due to increased production.
Energen’s adjusted EBITDAX totaled $142.4 million in the 2nd
quarter of 2017, increased 49 percent from the first quarter, and
exceeded internal expectations by 4 percent. In the same period a
year ago, Energen’s adjusted EBITDAX totaled $82.3 million. [See
“Non-GAAP Financial Measures” beginning on pp 8 for more
information and reconciliation.]
Commodity 2Q17
1Q17 Actual
June Rev.Guidance
% ∆
MayGuidance
% ∆
Oil 45.1
44.9 0 40.6
11 33.3
NGL 13.5
12.8 5 10.5
29 8.9
Natural Gas 13.9
13.5 3 11.1
25 10.6
Total 72.5 71.1
2 62.2 17
52.8
Area 2Q17 1Q17
Actual
June Rev.Guidance
% ∆
MayGuidance
% ∆
Midland Basin 41.3
40.5 2 34.2
21 31.8
Delaware Basin
23.4 22.9 2
19.8 18 12.8
Central Basin/Other
7.9 7.7 3
8.2 (4) 8.3
Total
72.5 71.1 2
62.2 17 52.8
Note: Totals in production tables above
may not sum due to rounding.
2Q17 Expenses
Per BOE, except where noted 2Q17 1Q17
Actual
June GuidanceMidpoint
LOE (production costs, marketing & transportation)
$ 6.66 $ 7.25 $ 8.68
Production & ad valorem taxes (% of
revenues exc. hedges)
6.0% 6.9%
7.3%
DD&A $ 18.25
$ 18.30 $ 20.71
SG&A $
3.00 $ 3.35 $ 4.29
Exploration
(includes seismic, delay rentals, etc.)
$ 0.30 $ 0.25 $ 0.76
Interest
($mm) $ 9.1 $ 9.2 $
9.0
2Q17 Average Realized Prices
Commodity With Hedges
W/O Hedges Oil (per barrel) $
44.58 $ 44.54
NGL (per gallon) $
0.36 $ 0.36
Natural Gas (per mcf)
$ 2.38 $ 2.29
CY17 Guidance
Production (mboepd)
By Basin 1Q17a
2Q17a 3Q17e 4Q17e
CY17e Midland Basin 31.8 41.3
40.6 42.1 39.0 Delaware Basin
12.8 23.4 26.2
31.9 23.6 Central Basin Platform/Other 8.3
7.9 8.0 7.8 8.0 Total
52.8 72.5 74.8
81.9 70.6
By Commodity
1Q17a 2Q17a 3Q17e
4Q17e CY17e Oil 33.3
45.1 47.9 53.4 45.0 NGL
8.9 13.5 12.9
13.7 12.3 Gas 10.6 13.9
13.9 14.7 13.3 Total 52.8
72.5 74.8 81.9 70.6
Note: Totals in production tables above
may not sum due to rounding.
Operating Expenses
Per BOE, except where noted
1Q17a 2Q17a 3Q17e
4Q17e CY17e LOE*
$ 8.68 $ 6.66 $7.00-$7.30
$6.85-$7.15 $7.05-$7.45 Production & ad
valorem taxes** 7.3% 6.0%
6.4% 6.3% 6.5% DD&A
expense† $ 20.71 $ 18.25
$17.05-$17.45 $15.25-$15.75
$17.45-$17.85 SG&A $ 4.29 $ 3.00
$3.10-$3.40 $2.55-$2.85
$3.00-$3.40 Exploration†† $ 0.76 $ 0.30
$0.10-$0.15 $0.15-$0.20
$0.25-$0.35 Interest ($mm) $ 9.0 $ 9.1
$9.5-$10.5 $10.0-$11.0
$38.5-$39.5 Effective tax rate 32%
35% 37%-39% 36%-38%
37%-39%
* Production costs, marketing &
transportation
** % of revenues, excluding hedges
† 4Q17 and CY17 does not include estimate
of 4Q17 DD&A look-back adjustment
†† Includes seismic, delay rentals,
etc.
LOE per boe in CY17 is estimated to range from $5.20-$5.50 in
the Delaware Basin, $5.85-$6.15 in the Midland Basin, and
$18.60-$18.90 in the Central Basin Platform. Production and ad
valorem taxes in CY17, as a percent of revenues excluding hedges,
are estimated to be 6.3 percent in the Delaware Basin, 6.4 percent
in the Midland Basin, and 7.4 percent in the Central Basin
Platform. SG&A per boe in CY17 is estimated to be comprised of
cash and other of $2.50-$2.70 per boe and non-cash, equity-based
compensation of $0.50-$0.70 per boe.
Hedges
For the last six months of 2017, 69 percent of the company’s
estimated oil production of 9.3 mmbo is hedged. Swaps for 4.0 mmbo
have an average NYMEX price of $50.68 per barrel, and 3-way collars
for 2.4 mmbo have average call, put, and short put prices of
$62.18, $45.00, and $35.00 per barrel, respectively. Approximately
40 percent of Energen’s estimated NGL production is hedged at an
average price of $0.57 per gallon, and 55 percent of its estimated
gas production is hedged at an average NYMEX-equivalent price of
$3.31 per Mcf. Energen also has hedged the WTI Midland to WTI
Cushing (sweet oil) differential for 5.6 million barrels at an
average price of $(0.66) per barrel; approximately 87 percent of
Energen’s oil production for the remainder of the year is estimated
to be sweet.
In 3Q17, approximately 73 percent of the company’s estimated oil
production of 4.4 mmbo is hedged. Swaps for 2.0 mmbo have an
average NYMEX price of $50.68 per barrel, and 3-way collars for 1.2
mmbo have average call, put, and short put prices of $62.18,
$45.00, and $35.00 per barrel, respectively. Approximately 42
percent of Energen’s estimated NGL production is hedged at an
average price of $0.57 per gallon, and 57 percent of its estimated
gas production is hedged at an average NYMEXe price of $3.30 per
Mcf. Energen also has hedged the Midland to Cushing differential
for 2.6 million barrels at an average price of $(0.64) per barrel;
approximately 68 percent of Energen’s estimated oil production in
3Q17 is estimated to be sweet.
Basis Differentials
Energen’s average realized prices in the last six months of CY17
will reflect commodity and basis hedges, oil transportation charges
of approximately $2.00 per barrel, NGL T&F fees of
approximately $0.12 per gallon, and basis differentials applicable
to unhedged production. Natural gas and NGL production also is
subject to a percent of proceeds contract of approximately 85%.
The assumed gas basis for all open contracts for August-December
2017 is $(0.45) per Mcf, and assumed prices for unhedged Midland to
Cushing basis differentials for sweet and sour oil
(August-December) are $(1.45) and $(1.30), respectively. Energen’s
assumed commodity prices for unhedged production are approximately
$47.30 per barrel of oil (July-December), $0.60 per gallon of NGL
(July-December), and $3.15 per Mcf of gas (August-December).
Estimated Price Realizations
(pre-hedge):
3Q17 ROY
2017 Crude oil (% of NYMEX/WTI) 93
93
NGL (after T&F) (% of NYMEX/WTI)
37 34
Natural gas (% of NYMEX/Henry Hub)
74 74
2018 Hedges
Oil 2018 Hedge
Volumes Avg. NYMEX Price Three way
Collars 13.5 mmbo Call Price
$ 60.04 per barrel
Put Price
$ 45.47 per barrel
Short Put Price
$ 35.47 per barrel
Commodity Hedge Volumes
NYMEXe Price NGL 105.8 mm
gallons $ 0.59 per gallon
Natural Gas
3.6 bcf $ 3.10 per mcf
Energen also has hedged the Midland to Cushing differential on
7.6 million barrels of its estimated 2018 sweet oil production at
an average price of $(1.10).
Conference Call
2Q17 slides associated with Energen’s quarterly release and
conference call are available at www.energen.com. Energen will hold
its quarterly conference call Tuesday, August 8, at 8:30 a.m. EDT.
Investment community members may participate by calling
1-877-407-8289 (reference Energen earnings call). A live audio
Webcast of the program as well as a replay may be accessed via
www.energen.com.
Energen Corporation is an oil-focused exploration and production
company with operations in the Permian Basin in west Texas and New
Mexico. For more information, go to www.energen.com.
FORWARD LOOKING STATEMENTS: All statements, other than
statements of historical fact, appearing in this release constitute
forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. These forward-looking
statements include, among other things, statements about our
expectations, beliefs, intentions or business strategies for the
future, statements concerning our outlook with regard to the timing
and amount of future production of oil, natural gas liquids and
natural gas, price realizations, the nature and timing of capital
expenditures for exploration and development, plans for funding
operations and drilling program capital expenditures, the timing
and success of specific projects, operating costs and other
expenses, proved oil and natural gas reserves, liquidity and
capital resources, outcomes and effects of litigation, claims and
disputes and derivative activities. Forward-looking statements may
include words such as “anticipate,” “believe,” “could,” “estimate,”
“expect,” “forecast,” “foresee,” “intend,” “may,” “plan,”
“potential,” “predict,” “project,” “seek,” “will” or other words or
expressions concerning matters that are not historical facts. These
statements involve certain risks and uncertainties that may cause
actual results to differ materially from expectations as of the
date of this news release. Except as otherwise disclosed, the
forward-looking statements do not reflect the impact of possible or
pending acquisitions, investments, divestitures or restructurings.
The absence of errors in input data, calculations and formulas used
in estimates, assumptions and forecasts cannot be guaranteed. We
base our forward-looking statements on information currently
available to us, and we undertake no obligation to correct or
update these statements whether as a result of new information,
future events or otherwise. Additional information regarding our
forward‐looking statements and related risks and uncertainties that
could affect future results of Energen, can be found in the
Company’s periodic reports filed with the Securities and Exchange
Commission and available on the Company’s website -
www.energen.com.
CAUTIONARY STATEMENTS: The SEC permits oil and gas companies
to disclose in SEC filings only proved, probable and possible
reserves that meet the SEC’s definitions for such terms, and price
and cost sensitivities for such reserves, and prohibits disclosure
of resources that do not constitute such reserves. Outside of SEC
filings, we use the terms “estimated ultimate recovery” or “EUR,”
reserve or resource “potential,” “contingent resources” and other
descriptions of volumes of non-proved reserves or resources
potentially recoverable through additional drilling or recovery
techniques. These estimates are inherently more speculative than
estimates of proved reserves and are subject to substantially
greater risk of actually being realized. We have not risked EUR
estimates, potential drilling locations, and resource potential
estimates. Actual locations drilled and quantities that may be
ultimately recovered may differ substantially from estimates. We
make no commitment to drill all of the drilling locations that have
been attributed these quantities. Factors affecting ultimate
recovery include the scope of our on-going drilling program, which
will be directly affected by the availability of capital, drilling,
and production costs, availability of drilling and completion
services and equipment, drilling results, lease expirations,
regulatory approvals, and geological and mechanical factors.
Estimates of unproved reserves, type/decline curves, per-well EURs,
and resource potential may change significantly as development of
our oil and gas assets provides additional data. Additionally,
initial production rates contained in this news release are subject
to decline over time and should not be regarded as reflective of
sustained production levels.
Financial, operating, and support data
pertaining to all reporting periods included in this release are
unaudited and subject to revision.
Non-GAAP Financial Measures
Adjusted Net Income is a Non-GAAP
financial measure (GAAP refers to generally accepted accounting
principles) which excludes the effects of certain non-cash
mark-to-market derivative financial instruments. Adjusted income
from continuing operations further excludes impairment losses,
certain prior period losses associated with a reduction in force,
and income associated with divestitures. Energen believes that
excluding the impact of these items is more useful to analysts and
investors in comparing the results of operations and operational
trends between reporting periods and relative to other oil and gas
producing companies.
Three Months Ended 6/30/17 Energen
Net Income ($ in millions except per share data)
Net Income
Per DilutedShare
Net Income (Loss) All Operations (GAAP) 29.5
0.30 Non-cash mark-to-market gains (net of $13.2
tax) (24.1 ) (0.25 ) Asset
impairment, other (net of tax) nm
nm Adjusted Income from Continuing
Operations (Non-GAAP) 5.4
0.06 Three Months Ended
6/30/16 Energen Net Income ($ in millions except per share
data) Net Income
Per DilutedShare
Net Income (Loss) All Operations (GAAP) 36.8
0.38 Non-cash mark-to-market losses (net of $21.5
tax) 39.1 0.40 Reduction in force expenses
(net of $0.3 tax) 0.6 0.01 Income associated
with 2016 property sales (net of $58.2 tax)
(103.5 ) (1.06 )
Adjusted Income from Continuing Operations (Non-GAAP)
(27.1 ) (0.28 )
Note: Amounts may not sum due to rounding
Non-GAAP Financial Measures
Earnings before interest, taxes,
depreciation, depletion, amortization and exploration expenses
(EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally
accepted accounting principles). Adjusted EBITDAX from
continuing operations further excludes impairment losses, certain
non-cash mark-to-market derivative financial instruments, prior
period losses associated with a reduction in force, and income
associated with divestitures. Energen believes these
measures allow analysts and investors to understand the financial
performance of the company from core business operations, without
including the effects of capital structure, tax rates and
depreciation. Further, this measure is useful in comparing the
company and other oil and gas producing companies.
Reconciliation To GAAP Information Three Months
Ended 6/30 ($ in millions) 2017
2016 Energen Net Income (Loss)
(GAAP) 29.5 36.8 Income associated with 2016
property sales, net of tax 0.0
(103.5 ) Net Income (Loss) Excluding
2016 Property Sales (Non-GAAP) 29.5
(66.8 ) Interest expense
9.1 9.0 Income tax expense (benefit) *
16.1 (35.1 ) Depreciation, depletion and
amortization * 121.5 110.6 Accretion expense
* 1.4 1.5 Exploration expense * 2.0
1.5 Adjustment for asset impairment nm
0.0 Adjustment for mark-to-market (gains)/ losses
(37.3 ) 60.6 Adjustment for reduction in
force expenses 0.0
0.9 Energen Adjusted EBITDAX from Continuing
Operations (Non-GAAP) 142.4
82.3 Note: Amounts may not
sum due to rounding * Amount adjusted to exclude
property sales in prior period. See reconciliation to GAAP
Information for the Three Months Ended 6/30/16.
Non-GAAP Financial Measures
The consolidated statement of income
excluding certain divestments is a Non-GAAP financial measure (GAAP
refers to generally accepted accounting principles). Energen
believes excluding information associated with 2016 property sales
provides analysts and investors useful information to understand
the financial performance of the company from ongoing business
operations. Further, this information is useful in
comparing the company and other oil and gas producing companies
operating primarily in the Permian Basin.
Energen Net Income
(Loss) Excluding 2016 Property Sales Reconciliation to GAAP
Information Three Months Ended June 30, 2016
(in thousands except per share and production data)
GAAP
2016 Property Sales Non-GAAP
Revenues Oil, natural gas liquids and natural gas
sales $ 171,637 $ 14,426 $
157,211 Gain (loss) on derivative instruments
(65,872 ) $
- (65,872 )
Total Revenues 105,765
14,426
91,339 Operating Costs and Expenses Oil,
natural gas liquids and natural gas production 42,840
5,660 37,180 Production and ad valorem taxes
11,265 1,236 10,029 O&G Depreciation,
depletion and amortization 115,768 6,368
109,400 FF&E Depreciation, depletion and
amortization 1,267 71 1,196 Asset
impairment - - - Exploration
1,520 32 1,488 General and administrative
† 23,548 10 23,538 Accretion of
discount on asset retirement obligations 1,779
248 1,531 (Gain) loss on sale of assets and
other (161,097 )
(160,944 )
(153 ) Total costs and expenses
36,890 (147,319
) 184,209 Operating
Income (Loss) 68,875
161,745
(92,870 ) Other Income/(Expense) Interest
expense (9,038 ) - (9,038 )
Other income 63
(1 ) 64
Total other expense
(8,975 )
(1 ) (8,974 )
Income (Loss) Before Income Taxes 59,900
161,744 (101,844 ) Income tax expense
(benefit) 23,141
58,204
(35,063 ) Net Income (Loss)
$ 36,759 $ 103,540
$ (66,781 )
Diluted
Earnings Per Average Common Share $
0.38 $ 1.06
$ (0.69 )
Basic earning Per
Average Common Share $ 0.38
$ 1.06 $
(0.69 ) Oil 3,558 238
3,320 NGL 1,067 212 855
Natural Gas 1,216
292 924
Total Production (mboe)
5,841 742
5,099 Total Production (boepd)
64,187
8,154 56,033
Note: Amounts may not sum due to rounding †
General and administrative includes $866 of expense related to the
reductions in force
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
For the 3 months ending June 30, 2017
and 2016
2nd Quarter (in thousands, except per
share data)
2017 2016
Change
Revenues Oil, natural gas liquids and
natural gas sales
$ 218,723 $ 171,637 $ 47,086 Gain
(loss) on derivative instruments, net
38,101 (65,872 )
103,973 Total revenues
256,824 105,765
151,059
Operating Costs and
Expenses Oil, natural gas liquids and natural gas production
43,909 42,840 1,069 Production and ad valorem taxes
13,218 11,265 1,953 Depreciation, depletion and amortization
121,549 117,035 4,514 Asset impairment
29 − 29
Exploration
1,998 1,520 478
General and administrative (including
stock based compensation of $3,191 and $5,504 for the three months
ended June 30, 2017, and 2016, respectively)
19,792
23,548
(3,756
)
Accretion of discount on asset retirement obligations
1,443
1,779 (336 ) (Gain) loss on sale of assets and other
172 (161,097 )
161,269 Total operating costs and
expenses
202,110
36,890 165,220
Operating Income 54,714
68,875 (14,161 )
Other Income (Expense) Interest expense
(9,145
) (9,038 ) (107 ) Other income
45 63
(18 ) Total other expense
(9,100 ) (8,975 )
(125 )
Income Before Income Taxes
45,614 59,900 (14,286 ) Income tax expense
16,133 23,141
(7,008 )
Net Income
$ 29,481 $ 36,759
$ (7,278 )
Diluted Earnings Per Average Common
Share $ 0.30 $
0.38 $ (0.08 )
Basic Earnings Per Average
Common Share $ 0.30
$ 0.38 $ (0.08 )
Diluted Average
Common Shares Outstanding 97,693
97,389 304
Basic Average Common Shares Outstanding
97,189 97,067
122
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
For the 6 months ending June 30, 2017
and 2016
Year-to-date (in thousands, except per
share data)
2017 2016
Change
Revenues Oil, natural gas liquids and
natural gas sales
$ 395,098 $ 294,401 $ 100,697 Gain
(loss) on derivative instruments, net
102,647 (60,417 )
163,064 Total revenues
497,745 233,984
263,761
Operating Costs and
Expenses Oil, natural gas liquids and natural gas production
85,197 90,567 (5,370 ) Production and ad valorem taxes
26,038 22,435 3,603 Depreciation, depletion and amortization
221,201 236,397 (15,196 ) Asset impairment
1,489
220,025 (218,536 ) Exploration
5,634 1,762 3,872 General and
administrative (including stock based compensation of $6,388 and
$7,975 for the six months ended June 30, 2017, and 2016,
respectively)
40,191
53,073
(12,882
)
Accretion of discount on asset retirement obligations
2,857
3,536 (679 ) Gain on sale of assets and other
(1,003 ) (160,875 )
159,872 Total operating costs and
expenses
381,604
466,920 (85,316 )
Operating Income (Loss) 116,141
(232,936 ) 349,077
Other Income (Expense) Interest expense
(18,111 ) (18,871 ) 760 Other income
428 159
269 Total other expense
(17,683 ) (18,712 )
1,029
Income (Loss) Before
Income Taxes 98,458 (251,648 ) 350,106 Income tax
expense (benefit)
35,574
(85,291 ) 120,865
Net Income (Loss) $ 62,884
$ (166,357 ) $ 229,241
Diluted Earnings Per Average Common Share
$ 0.64 $ (1.81 )
$ 2.45
Basic Earnings Per Average Common Share
$ 0.65 $ (1.81 )
$ 2.46
Diluted Average Common Shares
Outstanding 97,648
91,850 5,798
Basic Average Common Shares Outstanding
97,165 91,850
5,315
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
As of June 30, 2017 and December 31,
2016
(in thousands)
June
30, 2017 December 31, 2016
ASSETS Current Assets Cash and cash equivalents
$ 498 $ 386,093 Accounts receivable, net
104,359 73,322 Inventories, net
18,263 14,222
Derivative instruments
39,063 50 Income tax receivable
301 27,153 Prepayments and other
4,410 5,071 Total current assets
166,894 505,911
Property, Plant and Equipment Oil and natural gas
properties, net
4,513,743 4,016,683 Other property and
equipment, net
45,241
44,869 Total property, plant and equipment, net
4,558,984
4,061,552 Other postretirement assets
3,595 3,619
Noncurrent derivative instruments
9,534 − Other assets
7,725 8,741
TOTAL ASSETS $ 4,746,732
$ 4,579,823
LIABILITIES AND SHAREHOLDERS’
EQUITY
Current Liabilities Long-term debt due within one year
17,000 24,000 Accounts payable
65,770 65,031 Accrued
taxes
12,734 7,252 Accrued wages and benefits
15,709
25,089 Accrued capital costs
95,509 79,988 Revenue and
royalty payable
48,332 51,217 Derivative instruments
481 65,467 Other
17,778
20,160 Total current liabilities
273,313 338,204 Long-term
debt
659,158 527,443 Asset retirement obligations
84,867 81,544 Deferred income taxes
532,605 495,888
Noncurrent derivative instruments
502 3,006 Other long-term
liabilities
8,545 13,136 Total liabilities
1,558,990 1,459,221
Total Shareholders’ Equity
3,187,742 3,120,602
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY $
4,746,732 $ 4,579,823
SELECTED BUSINESS SEGMENT DATA
(UNAUDITED)
For the 3 months ending June 30, 2017
and 2016
2nd Quarter (in thousands, except sales price
and per unit data)
2017
2016 Change
Operating and production
data Oil, natural gas liquids and natural gas sales Oil
$ 182,701 $ 146,360 $ 36,341 Natural gas liquids
18,634 13,928 4,706 Natural gas
17,388 11,349
6,039 Total
$
218,723 $ 171,637
$ 47,086 Open non-cash mark-to-market gains (losses)
on derivative instruments Oil
$ 31,067 $ (54,729 ) $
85,796 Natural gas liquids
4,530 − 4,530 Natural gas
1,737 (5,896 )
7,633 Total
$
37,334 $ (60,625 ) $
97,959 Closed gains (losses) on derivative
instruments Oil
$ 152 $ (6,297 ) $ 6,449 Natural gas
liquids
(80 ) − (80 ) Natural gas
695 1,050
(355 ) Total
$ 767
$ (5,247 ) $ 6,014 Total
revenues
$ 256,824
$ 105,765 $ 151,059 Production
volumes Oil (MBbl)
4,102 3,558 544 Natural gas liquids
(MMgal)
51.6 44.8 6.8 Natural gas (MMcf)
7,596 7,296
300
Total production volumes (MBOE)
6,596
5,841 755
Average daily production volumes
Oil (MBbl/d)
45.1
39.1
6.0
Natural gas liquids (MMgal/d)
0.6 0.5 0.1 Natural gas
(MMcf/d)
83.5
80.2 3.3 Total average
daily production volumes (MBOE/d)
72.5
64.2 8.3
Average realized prices excluding effects of open
non-cash mark-to-market derivative instruments Oil (per barrel)
$ 44.58 $ 39.37 $ 5.21 Natural gas liquids (per
gallon)
$ 0.36 $ 0.31 $ 0.05 Natural gas (per Mcf)
$ 2.38 $ 1.70 $ 0.68 Average realized prices
excluding effects of all derivative instruments Oil (per barrel)
$ 44.54 $ 41.14 $ 3.40 Natural gas liquids (per
gallon)
$ 0.36 $ 0.31 $ 0.05 Natural gas (per Mcf)
$ 2.29 $ 1.56 $ 0.73 Costs per BOE Oil,
natural gas liquids and natural gas production expenses
$
6.66
$
7.34
$
(0.68
)
Production and ad valorem taxes
$ 2.00 $ 1.93 $ 0.07
Depreciation, depletion and amortization
$ 18.43 $
20.04 $ (1.61 ) Exploration expense
$ 0.30 $ 0.26 $
0.04 General and administrative
$ 3.00 $ 4.03 $ (1.03
) Capital expenditures (including acquisitions)
$ 336,111 $ 92,962
$ 243,149
SELECTED BUSINESS SEGMENT DATA
(UNAUDITED)
For the 6 months ending June 30, 2017
and 2016
Year-to-date (in thousands, except sales price
and per unit data)
2017
2016 Change
Operating and production
data Oil, natural gas liquids and natural gas sales Oil
$ 329,371 $ 248,517 $ 80,854 Natural gas liquids
34,268 22,517 11,751 Natural gas
31,459 23,367
8,092 Total
$
395,098 $ 294,401
$ 100,697 Open non-cash mark-to-market gains (losses)
on derivative instruments Oil
$ 89,125 $ (56,428 ) $
145,553 Natural gas liquids
11,617 − 11,617 Natural gas
8,961
(4,454 ) 13,415 Total
$ 109,703 $ (60,882 )
$ 170,585 Closed gains (losses) on derivative
instruments Oil
$ (5,858 ) $ (1,203 ) $ (4,655
) Natural gas liquids
(1,545 ) − (1,545 ) Natural gas
347 1,668
(1,321 ) Total
$
(7,056 ) $ 465 $
(7,521 ) Total revenues
$ 497,745
$ 233,984 $ 263,761
Production volumes Oil (MBbl)
7,098 6,944 154
Natural gas liquids (MMgal)
85.3 84.8 0.5 Natural gas (MMcf)
13,326
14,742 (1,416 )
Total production volumes (MBOE)
11,350
11,421 (71
)
Average daily production volumes
Oil (MBbl/d)
39.2
38.2
1.0
Natural gas liquids (MMgal/d)
0.5 0.5 − Natural gas (MMcf/d)
73.6 81.0
(7.4 ) Total average daily production
volumes (MBOE/d)
62.7
62.8 (0.1 )
Average realized prices excluding effects of open non-cash
mark-to-market derivative instruments Oil (per barrel)
$
45.58 $ 35.62 $ 9.96 Natural gas liquids (per gallon)
$ 0.38 $ 0.27 $ 0.11 Natural gas (per Mcf)
$
2.39 $ 1.70 $ 0.69 Average realized prices excluding
effects of all derivative instruments Oil (per barrel)
$
46.40 $ 35.79 $ 10.61 Natural gas liquids (per gallon)
$ 0.40 $ 0.27 $ 0.13 Natural gas (per Mcf)
$
2.36 $ 1.59 $ 0.77 Costs per BOE Oil, natural gas
liquids and natural gas production expenses
$
7.51
$
7.93
$
(0.42
)
Production and ad valorem taxes
$ 2.29 $ 1.96 $ 0.33
Depreciation, depletion and amortization
$ 19.49 $
20.70 $ (1.21 ) Exploration expense
$ 0.50 $ 0.15 $
0.35 General and administrative
$ 3.54 $ 4.65 $ (1.11
) Capital expenditures (includes acquisitions)
$ 720,246 $ 217,050
$ 503,196
View source
version on businesswire.com: http://www.businesswire.com/news/home/20170808005486/en/
Energen CorporationJulie S. Ryland, 205-326-8421
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