HOUSTON--(BUSINESS WIRE)--
Contango Oil & Gas Company (NYSE MKT: MCF) (“Contango”) announced today
its fourth quarter production results, year-end reserves, preliminary
2015 capital program and provided an operational update on recent
drilling activity.
Allan Keel, President and CEO of Contango, commented: “We believe that
the appropriate strategy for creating shareholder value in this low
commodity price, high cost environment is to reduce drilling activity,
utilize excess cash flow to improve our already strong financial
profile, and stay positioned to potentially take advantage of growth
opportunities that might surface in the near future as capital-stressed
companies shed assets, search for JV partners or pursue long term
strategic alternatives. Our financial flexibility, and inventory of
drilling locations, also position us to expand our 2015 capex program if
commodity prices improve, service costs decline, or both.” But more
importantly, drilling development wells and selling our product into
this environment, we believe is counter-productive to enhancing
shareholder value. Since a substantial portion of the present value of
production from new wells is realized within the first 18 months of a
well’s life, i.e. during this low price environment, and because the
cost of drilling those wells is expected to decline as the service
sector cost structure aligns with the commodity price environment, we
believe that drilling activity should be limited to only that which is
necessary to meet short-term lease expirations, and in some cases,
strategic exploratory test wells that potentially expose us to multiple
long-term growth opportunities if successful.
Fourth Quarter Production Results
Production for the fourth quarter of 2014 was approximately 9.8 Bcfe, or
106.2 Mmcfe per day. Production for the fourth quarter was approximately
3% less than production for the fourth quarter of 2013, due primarily to
our transition to a multi-well pad drilling strategy in our Chalktown
area late in the third quarter of 2014. The change to multi-well pad
drilling provides drilling cost efficiencies and overall recovery
enhancement; however, the related delay in initial production from the
two new three-well pads drilled in September through December precluded
us from increasing production compared to the prior year quarter. One
multi-well pad began producing in mid-January at a restricted rate due
to limited natural gas takeaway capacity, while the second multi-well
pad is expected to begin production in late-March. Further impacting
fourth quarter production, and expected production for 2015, was a
reduction in drilling activity associated with the dramatic downturn in
crude oil and natural gas prices during the fourth quarter. Partially
offsetting this decrease in production was increased production from
additional interests in our Dutch wells acquired in December 2013 and
new production from our 2013 discovery at South Timbalier 17 which began
producing in July 2014. Crude oil and natural gas liquids production
during the fourth quarter of 2014 was approximately 5,600 barrels per
day, or 32% of total production, compared to approximately 6,300 barrels
per day, or 34% of total production, in the fourth quarter of 2013, a
decline also associated with the lower capital expenditures in the
fourth quarter and the change in drilling strategy in our Chalktown
area. Our first quarter 2015 production guidance of 95-105 Mmcfed
reflects the impact of the lower fourth quarter 2014 capital program,
the expected delays in attaining full production rates from new
multi-well pads drilled in our Chalktown area and our decision to reduce
our planned 2015 capital program (as described herein) due to the low
and uncertain commodity price environment.
Year-end 2014 Proved Reserves
As of December 31, 2014, our independent third-party engineering firms
estimated our proved oil and natural gas reserves to be approximately
275.2 Bcfe, of which 65% was natural gas, 18% was oil and condensate,
and 17% was natural gas liquids. This represents a 12% decrease compared
to our proved reserves reported as of December 31, 2013. Exclusive of an
approximate 22.4 Bcfe negative revision of proved developed producing
reserves at our Eugene Island 11 field, reserves as of December 31, 2014
would have been approximately 5% lower than the prior year reserves,
mainly attributable to the change in late 2014 drilling strategy and
normal production decline. The negative revision at Eugene Island 11
resulted from a change in forecasted condensate yield and lower original
gas in place, as determined by our third party engineers as a result of
recent field performance and a pressure study done in conjunction with
the recent shut-in for compression installation. As of December 31,
2013, our reported proved reserves were 66% natural gas, 19% oil and
condensate, and 15% natural gas liquids. These estimates were prepared
in accordance with reserve reporting guidelines mandated by the
Securities and Exchange Commission. These estimates do not include net
reserves of approximately 70.2 Bcfe attributable to our 37% equity
ownership interest in Exaro Energy III LLC (“Exaro”) as of December 31,
2014.
As of December 31, 2014, the PV-10 value of our proved reserves was
approximately $797 million, compared to our PV-10 value of $987 million
as of December 31, 2013. The decrease in PV-10 year over year can be
attributed to 2014 production, the negative revision to our Eugene
Island 11 reserves, the slowdown in drilling activity in the fourth
quarter of 2014 and the decrease in crude oil and natural gas liquids
prices. As of December 31, 2014, the average adjusted product prices
over the remaining lives of the reserves used in determining our proved
reserves and PV-10 value were $92.89/Bbl for oil and condensate,
$4.38/Mmbtu for natural gas and $33.45/Bbl for natural gas liquids. As
of December 31, 2013, the average adjusted product prices over the
remaining lives of the reserves used in determining our proved reserves
and PV-10 value were $106.80/Bbl for oil and condensate, $3.73/Mmbtu for
natural gas and $35.92/Bbl for natural gas liquids.
Our proved developed reserves for the year ended December 31, 2014
decreased by 46.9 Bcfe. Of this amount, 40.4 Bcfe related to production
during the year and 22.4 Bcfe related to the negative revision at Eugene
Island 11 discussed above, partially offset by 9.4 Bcfe in positive
onshore revisions and 6.5 Bcfe in extensions and discoveries from our
2014 drilling program.
Our proved undeveloped reserves for the year ended December 31, 2014
increased by 8.2 Bcfe, an increase attributable to our 2014 drilling
program that added 27.0 Bcfe, partially offset by negative revisions of
17.2 Bcfe associated with a revised type curve for our Force area of our
Madison/Grimes acreage.
2015 Capital Program
As a result of the dramatic downturn in crude oil, natural gas and
natural gas liquids prices in late 2014 and 2015, the negative impact of
those price declines on the economics of most domestic resource plays,
and the continuing uncertainty as to when, or how much, the commodity
price environment might improve, we believe that deferring further
drilling in our current resource plays until prices improve is the most
prudent strategy to pursue at this time. Since 60-70% of the PV-10 of a
typical resource well’s life (in our areas, and on a flat price basis)
is produced within the first 18 months, we believe that the deferral of
further drilling in our areas pending a better price environment is a
better strategy for realizing value from our portfolio. Accordingly, our
capital expenditure program for 2015 will be focused on: 1) the
enhancement of our already strong and flexible financial position
through limiting our capital expenditure budget to no more than
internally generated cash flow; 2) focusing drilling expenditures on
strategic projects; and 3) identifying and implementing opportunities
for cost efficiencies and improvements in all areas of our operations.
Though not formally incorporated in our 2015 budget, our strong
financial liquidity position should allow us to be opportunistic and
take advantage of new resource potential opportunities, organically or
through acquisition, which we might identify in a continuing low
commodity price environment. Our current capital budget of approximately
$51 million for 2015 will allow us to meet our contractual requirements,
remain in position to preserve our term acreage where appropriate and
improve our financial profile by lowering overall Company liabilities.
Our current 2015 capital budget represents a decrease of 73% compared to
our total 2014 capital expenditures of $189 million, and a 68% decrease
in onshore, drilling capital expenditures. We have the flexibility,
liquidity, and inventory to significantly increase our level of spending
should circumstances change over the course of the year. Our specific
plans, by area, include:
--
|
|
|
Southeast Texas Woodbine/Lewisville – We forecast capital
expenditures of approximately $11.8 million in Madison and Grimes
counties to finalize the drilling, completion and commencement of
production on six Woodbine wells (3.9 net) drilled from two
multi-well pads beginning in the fourth quarter and continuing
through the first quarter of 2015, plus an additional two gross (1.1
net) wells not utilizing a multi-well pad drilling strategy, to
further delineate our Chalktown area. Additionally, we have budgeted
$5.4 million to finalize drilling and complete one gross (0.9 net)
well in our Iola/Grimes area.
|
|
|
|
|
|
|
|
Also budgeted is $4.1 million to drill a pilot and potential
horizontal well to evaluate the prospectivity of the Lower
Lewisville formation in the Chalktown area. To date, all of our
Lewisville tests in the Chalktown area have been in the Upper
Lewisville.
|
|
|
|
|
--
|
|
|
South Texas - We forecast capital expenditures of approximately
$5.5 million in Fayette/Gonzales counties in 2015 to complete the
initial five-well program originally planned for our Elm Hill
project, after which we will evaluate and report results and
develop a strategy for further activity in the area. We also
anticipate spending approximately $3.0 million dollars during 2015
to test the Eagle Ford Shale on our KM Ranch acreage in Zavala
County.
|
|
|
|
|
--
|
|
|
Wyoming – We forecast capital expenditures of approximately $10.7
million to finalize the drilling and completion of our initial Mowry
Shale test well spud in December in Natrona County and to drill and
complete our initial Muddy Sandstone test well spud in January in
Weston County. Both wells will be fraced in late March or early
April, with results to follow.
|
|
|
|
|
--
|
|
|
We have budgeted approximately $8.5 million for the acquisition of
new leases and seismic data for the expansion of our drilling
inventory in our current positions, or investment in new plays, and
have ample liquidity to devote additional capital to test new
opportunities should those opportunities present themselves.
|
We will continuously monitor commodity prices and the expected decline
in service/supply costs during the year, and if deemed appropriate, we
possess the financial flexibility to expand our drilling program for the
remainder of the year.
Drilling Activity Update
Southeast Texas (Woodbine)
Chalktown Area, Madison County, Texas
We initiated a multi-well pad drilling strategy on 500 foot spacing in
our Chalktown area late in the third quarter of 2014, a strategy where
three wells are drilled in succession, completed in succession, and then
put on production simultaneously to maximize recovery. Results of fourth
quarter activity are as follows:
PAD 1
|
|
|
|
WI%
|
|
|
|
Total Measured Depth (ft.)
|
|
|
|
Lateral (ft.)
|
|
|
|
Frac Stages
|
|
|
|
First Production
|
|
|
|
30 Day Avg IP (boed)
|
|
|
|
% Oil
|
Vick Trust B 2H
|
|
|
|
69%
|
|
|
|
16,163
|
|
|
|
7,260
|
|
|
|
30
|
|
|
|
January 2015
|
|
|
|
not yet available
|
Vick Trust B 3H
|
|
|
|
67%
|
|
|
|
15,818
|
|
|
|
6,542
|
|
|
|
29
|
|
|
|
January 2015
|
|
|
|
not yet available
|
Vick Trust B 5H
|
|
|
|
69%
|
|
|
|
16,235
|
|
|
|
7,360
|
|
|
|
28
|
|
|
|
January 2015
|
|
|
|
not yet available
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PAD 2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barr Unit A 2H *
|
|
|
|
51%
|
|
|
|
15,570
|
|
|
|
6,554
|
|
|
|
TBD
|
|
|
|
Completing
|
|
|
|
TBD
|
|
|
|
TBD
|
Barr Unit B 3H *
|
|
|
|
67%
|
|
|
|
15,250
|
|
|
|
5,583
|
|
|
|
TBD
|
|
|
|
Completing
|
|
|
|
TBD
|
|
|
|
TBD
|
Barr Unit B 4H *
|
|
|
|
67%
|
|
|
|
14,943
|
|
|
|
5,350
|
|
|
|
TBD
|
|
|
|
Completing
|
|
|
|
TBD
|
|
|
|
TBD
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barr Unit A 5H
|
|
|
|
51%
|
|
|
|
15,065
|
|
|
|
5,728
|
|
|
|
22
|
|
|
|
Completing
|
|
|
|
|
|
|
|
|
Viniarski A 1H
|
|
|
|
72%
|
|
|
|
16,773
|
|
|
|
7,656 E
|
|
|
|
30 E
|
|
|
|
Awaiting completion
|
|
|
|
|
|
|
|
|
Hoke 1H (Pilot)
|
|
|
|
70%
|
|
|
|
11,000 E
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Drilled from the same pad as the Barr Unit B 1H, which began
production in June 2014.
|
|
Iola/Grimes Area, Grimes County, Texas
We spud one well in Grimes County during the fourth quarter:
Well
|
|
|
|
WI%
|
|
|
|
Total Measured Depth (ft.)
|
|
|
|
Lateral (ft.)
|
|
|
|
Frac Stages
|
|
|
|
Status
|
|
|
|
30 Day Avg IP (boed)
|
|
|
|
% Oil
|
Norwood 2H
|
|
|
|
85%
|
|
|
|
17,699
|
|
|
|
7,744
|
|
|
|
30
|
|
|
|
Completing
|
|
|
|
TBD
|
|
|
|
TBD
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Norwood well was designed as an extended lateral into the Upper
Lewisville formation. The well will be completed using twice the number
of frac stages, four times the amount of proppant, and fifty percent
longer effective lateral lengths as our previous two attempts in the
Iola Grimes area. We believe that this test could have significant
impact on the southern portion of our leasehold.
South Texas (Buda), Zavala and Dimmit
Counties
Our recent activity in the Buda in South Texas consisted of the
following:
Well
|
|
|
|
WI%
|
|
|
|
Total Measured Depth (ft.)
|
|
|
|
Lateral (ft.)
|
|
|
|
Frac Stages
|
|
|
|
First Production
|
|
|
|
30 Day Avg IP (boed)
|
|
|
|
% Oil
|
Beeler Unit 26H
|
|
|
|
50%
|
|
|
|
13,207
|
|
|
|
6,273
|
|
|
|
n/a
|
|
|
|
October 2014
|
|
|
|
218
|
|
|
|
80%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Since May of 2013, we have drilled or participated in 19 wells within
the Buda trend and believe that we have defined the optimum spacing and
productive sweet spot. Additional drilling in the Buda will be limited
going forward; instead we will drill an Eagle Ford Shale well on our KM
Ranch acreage in Zavala County utilizing a longer lateral, more frac
stage and more proppant strategy than we used in our two previous wells
in this area.
Additionally, during the fourth quarter of 2014, we drilled the Beeler
Unit 24H as a vertical pilot well to evaluate the Eagle Ford in Zavala
and Dimmit Counties. We are evaluating the recovered core data prior to
deciding on a new development strategy for the Eagle Ford in these areas.
Fayette & Gonzales County, Texas (Elm Hill
Project)
We brought three wells on production on our Elm Hill project during the
quarter, and spud two additional wells. We continue to lease in this
area, so we have presented limited information on the results on our
drilling activity due to competition in the area.
Well
|
|
|
|
WI%
|
|
|
|
Total Measured Depth (ft.)
|
|
|
|
Status /First Production
|
Janecka 1H
|
|
|
|
50%
|
|
|
|
11,758
|
|
|
|
November 2014
|
Vinklarek 1H
|
|
|
|
50%
|
|
|
|
10,793
|
|
|
|
December 2014
|
Ochs 1H
|
|
|
|
50%
|
|
|
|
12,400
|
|
|
|
Jan-15
|
Henderson 1H
|
|
|
|
50%
|
|
|
|
15,513
|
|
|
|
Completing
|
Jennifer 1H
|
|
|
|
50%
|
|
|
|
13,700 E
|
|
|
|
Drilling @ 7,500 ft
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We expect to analyze and evaluate the combined results and then confer
with our partner to determine a future strategy for our 56,000 gross
acre position in the area.
Natrona County, Wyoming (FRAMS Project)
We drilled our first well in Natrona County during the fourth quarter,
targeting the Mowry Shale:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well
|
|
|
|
WI%
|
|
|
|
Total Measured
Depth (ft.)
|
|
|
|
Lateral (ft.)
|
|
|
|
Frac Stages
|
|
|
|
Status /First
Production
|
|
|
|
30 Day Avg IP
(boed)
|
|
|
|
% Oil
|
State 35-79-16 1H
|
|
|
|
60%
|
|
|
|
12,944
|
|
|
|
5,911
|
|
|
|
TBD
|
|
|
|
Completing
|
|
|
|
TBD
|
|
|
|
TBD
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The well was drilled to its intended total measured depth, with
completion operations expected to commence in March or April. We will
monitor results on this well for several months and determine future
drilling plans for this approximate 120,000 gross acre position.
Weston County, Wyoming (N. Cheyenne Project)
Upon completion of drilling on the Natrona County well, we moved the rig
to Weston County and spud our first well there in January 2015,
targeting the Muddy Sandstone formation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well
|
|
|
|
WI%
|
|
|
|
Total Measured
Depth (ft.)
|
|
|
|
Lateral (ft.)
|
|
|
|
Frac Stages
|
|
|
|
Status
|
|
|
|
30 Day Avg IP
(boed)
|
|
|
|
% Oil
|
Elliot 13-44-66 1H
|
|
|
|
80%
|
|
|
|
7,000 E
|
|
|
|
TBD
|
|
|
|
TBD
|
|
|
|
Drilling
|
|
|
|
TBD
|
|
|
|
TBD
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We are currently drilling the lateral section of this well and
anticipate reaching total depth prior to completion operations
commencing in Natrona County. Upon completion of the frac in Natrona
County, the crew will be mobilized to Weston County to begin completion
operations. We will also monitor results on this well for several months
and determine next steps for this 49,000 gross acre position.
Borrowing Base Reaffirmation
During the fourth quarter of 2014, our bank group reaffirmed our $275
million borrowing base under our senior revolving credit facility. The
borrowing base was reaffirmed through May 1, 2015, the next regularly
scheduled borrowing base redetermination date. As of December 31, 2014,
we had approximately $63.4 million outstanding under our credit facility.
Contango Oil & Gas Company is a Houston, Texas-based, independent energy
company engaged in the acquisition, exploration, development,
exploitation and production of crude oil and natural gas offshore in the
shallow waters of the Gulf of Mexico and in the onshore Texas Gulf Coast
and Rocky Mountain regions of the United States. Additional information
is available on the Company's website at http://contango.com.
This press release contains forward-looking statements regarding
Contango that are intended to be covered by the safe harbor
"forward-looking statements" provided by the Private Securities
Litigation Reform Act of 1995, based on Contango’s current expectations
and includes statements regarding acquisitions and divestitures,
estimates of future production, future results of operations, quality
and nature of the asset base, the assumptions upon which estimates are
based and other expectations, beliefs, plans, objectives, assumptions,
strategies or statements about future events or performance (often, but
not always, using words such as "expects", “projects”, "anticipates",
"plans", "estimates", "potential", "possible", "probable", or "intends",
or stating that certain actions, events or results "may", "will",
"should", or "could" be taken, occur or be achieved). Statements
concerning oil and gas reserves also may be deemed to be forward looking
statements in that they reflect estimates based on certain assumptions
that the resources involved can be economically exploited.
Forward-looking statements are based on current expectations, estimates
and projections that involve a number of risks and uncertainties, which
could cause actual results to differ materially from those, reflected in
the statements. These risks include, but are not limited to: the risks
of the oil and gas industry (for example, operational risks in exploring
for, developing and producing crude oil and natural gas; risks and
uncertainties involving geology of oil and gas deposits; the uncertainty
of reserve estimates; the uncertainty of estimates and projections
relating to future production, costs and expenses; potential delays or
changes in plans with respect to exploration or development projects or
capital expenditures; health, safety and environmental risks and risks
related to weather such as hurricanes and other natural disasters);
uncertainties as to the availability and cost of financing; fluctuations
in oil and gas prices; risks associated with derivative positions;
inability to realize expected value from acquisitions, inability of our
management team to execute its plans to meet its goals, shortages of
drilling equipment, oil field personnel and services, unavailability of
gathering systems, pipelines and processing facilities and the
possibility that government policies may change or governmental
approvals may be delayed or withheld. Additional information on these
and other factors which could affect Contango’s operations or financial
results are included in Contango’s other reports on file with the
Securities and Exchange Commission. Investors are cautioned that any
forward-looking statements are not guarantees of future performance and
actual results or developments may differ materially from the
projections in the forward-looking statements. Forward-looking
statements are based on the estimates and opinions of management at the
time the statements are made. Contango does not assume any obligation to
update forward-looking statements should circumstances or management's
estimates or opinions change. Initial production rates are subject to
decline over time and should not be regarded as reflective of sustained
production levels.