Contango Oil & Gas Company (NYSE MKT:MCF) (“Contango” or the
“Company”) announced today its financial results for the three and
six months ended June 30, 2017 and provided an operational
update.
Second Quarter Highlights
- Production of 5.3 Bcfe for the quarter, or 58.0 Mmcfed, within
guidance
- Revenues of $20.3 million for the quarter, up from $19.4
million for the prior year quarter
- Adjusted EBITDAX of $10.2 million for the quarter and net loss
of $6.0 million
- Brought two additional Southern Delaware Basin wells on
production, and are in various stages of drilling/completion on
three more
Summary Second Quarter Financial
Results
Net loss for the three months ended June 30,
2017 was $6.0 million, or $0.24 per basic and diluted share,
compared to a net loss of $17.3 million, or $0.90 per basic and
diluted share, for the same period last year. This improvement was
attributable primarily to higher revenues from higher commodity
prices, lower operating expenses due to cost reduction efforts,
lower depreciation, depletion, and amortization (“DD&A”)
expense and an improvement in the mark to market valuation of our
commodity price hedges. Average weighted shares outstanding were
approximately 24.7 million and 19.1 million for the current and
prior year quarters, respectively.
Revenues for the current quarter were
approximately $20.3 million compared to $19.4 million for the 2016
quarter, despite lower production during the current quarter. The
increase in commodity prices was more than sufficient to offset the
decline in production resulting from a very limited 2016 drilling
program.
The Company reported Adjusted EBITDAX, as
defined below, of approximately $10.2 million for the three months
ended June 30, 2017, compared to $10.1 million for the same period
last year, a slight increase attributable to the increase in
revenues and decrease in operating expenses, substantially offset
by the decrease in the realized gain on our commodity price
hedges.
Production for the second quarter of 2017 was
approximately 5.3 Bcfe, or 58.0 Mmcfe per day, within our
previously provided guidance, compared to 74.6 Mmcfe per day for
the second quarter of 2016. This expected decline in
production can be attributed to normal field decline, non-core
property sales and 61 days of decreased production rates at
Vermilion 170 due to temporary pipeline limitations. The field
decline was expected due to minimal new production added from a
reduced drilling program during the first half of 2016 in response
to the low commodity price environment. Crude oil and natural
gas liquids production during the second quarter of 2017 was
approximately 3,100 barrels per day, or 32% of total production,
compared to approximately 3,800 barrels per day, or 31% of total
production, in the second quarter of 2016. Natural gas production
during the current quarter was approximately 39.6 Mmcf per day, or
68% of total production, compared to approximately 51.4 Mmcf per
day, or 69% of total production, in the previous quarter, a decline
also related to the lower onshore capital expenditures in
2016. Our production guidance for the third quarter of 2017
is 56 – 61 Mmcfed, with the mid-point relatively flat with the
first and second quarter of 2017 as production from new drilling
begins to offset normal field decline. Because new production is
primarily liquids, we expect crude oil and natural gas liquids to
increase and represent approximately 33% of total production for
the third quarter.
The weighted average equivalent sales price
during the three months ended June 30, 2017 was $3.84 per Mcfe,
compared to $2.85 per Mcfe for the same period last year, as we
experienced increases of 9%, 55% and 19% in crude oil, natural gas
and natural gas liquids prices, respectively compared to the prior
year quarter.
Operating expenses for the three months ended
June 30, 2017 were approximately $6.3 million, or $1.20 per Mcfe,
compared to $7.0 million, or $1.03 per Mcfe, for the same period
last year. Included in operating expenses are direct lease
operating expenses, transportation and processing costs, workover
expenses and production and ad valorem taxes. Operating expenses
for the current quarter, exclusive of production and ad valorem
taxes were approximately $5.6 million, or $1.07 per Mcfe, compared
to approximately $5.9 million, or $0.86 per Mcfe, for the prior
year quarter. Our guidance for operating expenses for the third
quarter of 2017, exclusive of production and ad valorem taxes, is
between $6.8 to $7.3 million, higher than the recent quarter due to
additional workovers scheduled for the upcoming
quarter.
DD&A expense for the three months ended June
30, 2017 was $12.7 million, or $2.41 per Mcfe, compared to $17.9
million, or $2.63 per Mcfe, for the prior year quarter, a decrease
primarily attributable to lower production during the quarter and
the slight improvement in rate.
Impairment and abandonment expense of oil and
gas properties was $1.4 million for the current quarter, which
related to the partial impairment of two unused offshore
platforms. Impairment and abandonment expense of oil and gas
properties for the prior year quarter was $1.3 million, with
substantially all of that related to non-core, unproved properties
and prospects in Fayette and Gonzales counties, Texas.
Total G&A expenses, i.e. inclusive of stock
expense, for the three months ended June 30, 2017 were $5.8
million, or $1.11 per Mcfe, compared to $5.4 million, or $0.79 per
Mcfe, for the prior year quarter. G&A expenses for the
current and prior year quarters, exclusive of $1.6 million and $1.3
million, respectively, in non-cash stock compensation expense, were
comparable for both periods. For the third quarter of 2017, we have
provided guidance of $4.5 million to $5.1 million for general and
administrative expenses, exclusive of non-cash stock compensation
(“Cash G&A”).
Gain from affiliates (Exaro Energy III, LLC) for
the three months ended June 30, 2017 was approximately $0.2
million, compared to $1.3 million for the same period last
year.
2017 Capital Program
Capital costs incurred for the three months
ended June 30, 2017 were approximately $13.9 million, including
$0.8 million in paid and accrued leasehold acquisition costs and
$13.1 million for the drilling and completion of wells in the
Southern Delaware Basin in Pecos County, Texas. Our capital
expenditure budget for 2017 was originally forecasted to be $46.3
million, including $36.6 million to drill and/or complete nine
gross wells (4.0 net) on our Southern Delaware Basin acreage. We
have revised our 2017 budget to approximately $55 million, to
include an additional $9.0 million in drilling and completion costs
for one additional gross well (0.5 net), a saltwater disposal well,
and anticipated increases in the cost of vendor goods and
services.
As of June 30, 2017, we had approximately $71.3
million of debt outstanding under our credit facility.
Effective May, 4, 2017, the borrowing base under our facility was
redetermined at $125 million, which reflects the impact of lower
commodity prices, our limited drilling program in 2016 as well as
no current benefit from our 2017 drilling program as the borrowing
base was redetermined based on the 2016 year-end
reserves.
Derivative Instruments
We have the following financial derivative
contracts in place for the remainder of the year:
|
|
|
|
|
|
|
|
|
|
Commodity |
|
Period |
|
Derivative |
|
Volume/Month |
|
Price/Unit (1) |
Natural Gas |
|
July 2017 |
|
Collar |
|
400,000 MMBtus |
|
$ |
2.65 -
3.00 |
Natural Gas |
|
Aug - Oct 2017 |
|
Collar |
|
200,000 MMBtus |
|
$ |
2.65 -
3.00 |
Natural Gas |
|
Nov - Dec 2017 |
|
Collar |
|
400,000 MMBtus |
|
$ |
2.65 -
3.00 |
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
July 2017 |
|
Swap |
|
300,000 MMBtus |
|
$ |
3.51 |
Natural Gas |
|
Aug - Oct 2017 |
|
Swap |
|
70,000 MMBtus |
|
$ |
3.51 |
Natural Gas |
|
Nov - Dec 2017 |
|
Swap |
|
300,000 MMBtus |
|
$ |
3.51 |
|
|
|
|
|
|
|
|
|
|
Oil |
|
July 2017 |
|
Swap |
|
9,000 Bbls |
|
$ |
53.95 |
Oil |
|
Aug - Oct 2017 |
|
Swap |
|
6,000 Bbls |
|
$ |
53.95 |
Oil |
|
Nov - Dec 2017 |
|
Swap |
|
8,000 Bbls |
|
$ |
53.95 |
|
|
|
|
|
|
|
|
|
|
Oil |
|
Jul - Dec 2017 |
|
Swap |
|
9,000 Bbls |
|
$ |
56.20 |
(1) Commodity price derivatives based on Henry Hub NYMEX natural
gas prices and West Texas Intermediate oil prices, as
applicable.
Selected Financial and Operating DataThe
following table reflects certain comparative financial and
operating data for the three and six months ended June 30, 2017 and
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2017 |
|
2016 |
|
% |
|
2017 |
|
2016 |
|
% |
Offshore Volumes
Sold: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate (Mbbls) |
|
|
33 |
|
|
36 |
|
-8 |
% |
|
|
55 |
|
|
87 |
|
-37 |
% |
Natural
gas (Mmcf) |
|
|
2,908 |
|
|
3,676 |
|
-21 |
% |
|
|
5,916 |
|
|
7,515 |
|
-21 |
% |
Natural
gas liquids (Mbbls) |
|
|
83 |
|
|
111 |
|
-25 |
% |
|
|
167 |
|
|
223 |
|
-25 |
% |
Natural
gas equivalents (Mmcfe) |
|
|
3,602 |
|
|
4,559 |
|
-21 |
% |
|
|
7,248 |
|
|
9,379 |
|
-23 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Volumes
Sold: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate (Mbbls) |
|
|
109 |
|
|
131 |
|
-17 |
% |
|
|
201 |
|
|
265 |
|
-24 |
% |
Natural
gas (Mmcf) |
|
|
699 |
|
|
997 |
|
-30 |
% |
|
|
1,419 |
|
|
2,079 |
|
-32 |
% |
Natural
gas liquids (Mbbls) |
|
|
53 |
|
|
75 |
|
-29 |
% |
|
|
97 |
|
|
163 |
|
-40 |
% |
Natural
gas equivalents (Mmcfe) |
|
|
1,675 |
|
|
2,234 |
|
-25 |
% |
|
|
3,209 |
|
|
4,640 |
|
-31 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Volumes
Sold: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate (Mbbls) |
|
|
142 |
|
|
167 |
|
-15 |
% |
|
|
256 |
|
|
352 |
|
-27 |
% |
Natural
gas (Mmcf) |
|
|
3,607 |
|
|
4,673 |
|
-23 |
% |
|
|
7,335 |
|
|
9,594 |
|
-24 |
% |
Natural
gas liquids (Mbbls) |
|
|
136 |
|
|
186 |
|
-27 |
% |
|
|
264 |
|
|
386 |
|
-32 |
% |
Natural
gas equivalents (Mmcfe) |
|
|
5,277 |
|
|
6,793 |
|
-22 |
% |
|
|
10,457 |
|
|
14,019 |
|
-25 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily Sales
Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate (Mbbls) |
|
|
1.6 |
|
|
1.8 |
|
-15 |
% |
|
|
1.4 |
|
|
1.9 |
|
-27 |
% |
Natural
gas (Mmcf) |
|
|
39.6 |
|
|
51.4 |
|
-23 |
% |
|
|
40.5 |
|
|
52.7 |
|
-24 |
% |
Natural
gas liquids (Mbbls) |
|
|
1.5 |
|
|
2.0 |
|
-27 |
% |
|
|
1.5 |
|
|
2.1 |
|
-32 |
% |
Natural
gas equivalents (Mmcfe) |
|
|
58.0 |
|
|
74.6 |
|
-22 |
% |
|
|
57.8 |
|
|
77.0 |
|
-25 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales
prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate (per Bbl) |
|
$ |
45.61 |
|
$ |
41.80 |
|
9 |
% |
|
$ |
46.99 |
|
$ |
34.75 |
|
35 |
% |
Natural
gas (per Mcf) |
|
$ |
3.09 |
|
$ |
2.00 |
|
55 |
% |
|
$ |
3.04 |
|
$ |
2.01 |
|
51 |
% |
Natural
gas liquids (per Bbl) |
|
$ |
19.50 |
|
$ |
16.33 |
|
19 |
% |
|
$ |
20.40 |
|
$ |
14.09 |
|
45 |
% |
Total
(per Mcfe) |
|
$ |
3.84 |
|
$ |
2.85 |
|
35 |
% |
|
$ |
3.80 |
|
$ |
2.63 |
|
44 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2017 |
|
2016 |
|
% |
|
2017 |
|
2016 |
|
% |
Offshore Selected Costs
($ per Mcfe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses (1) |
|
$ |
0.66 |
|
$ |
0.52 |
|
27 |
% |
|
$ |
0.71 |
|
$ |
0.51 |
|
39 |
% |
Production and ad valorem taxes |
|
$ |
0.06 |
|
$ |
0.08 |
|
-25 |
% |
|
$ |
0.06 |
|
$ |
0.07 |
|
-14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Selected Costs
($ per Mcfe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses (1) |
|
$ |
1.94 |
|
$ |
1.56 |
|
24 |
% |
|
$ |
2.07 |
|
$ |
1.67 |
|
24 |
% |
Production and ad valorem taxes |
|
$ |
0.29 |
|
$ |
0.36 |
|
-19 |
% |
|
$ |
0.29 |
|
$ |
0.29 |
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selected Costs
($ per Mcfe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses (1) |
|
$ |
1.07 |
|
$ |
0.86 |
|
24 |
% |
|
$ |
1.13 |
|
$ |
0.89 |
|
27 |
% |
Production and ad valorem taxes |
|
$ |
0.13 |
|
$ |
0.17 |
|
-24 |
% |
|
$ |
0.13 |
|
$ |
0.15 |
|
-13 |
% |
General
and administrative expense (cash) |
|
$ |
0.80 |
|
$ |
0.60 |
|
33 |
% |
|
$ |
0.89 |
|
$ |
0.59 |
|
51 |
% |
Interest
expense |
|
$ |
0.18 |
|
$ |
0.17 |
|
6 |
% |
|
$ |
0.16 |
|
$ |
0.15 |
|
7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX (2)
(thousands) |
|
$ |
10,231 |
|
$ |
10,103 |
|
|
|
$ |
17,385 |
|
$ |
17,366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares
Outstanding (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
24,671 |
|
|
19,121 |
|
|
|
|
24,639 |
|
|
19,100 |
|
|
Diluted |
|
|
24,671 |
|
|
19,121 |
|
|
|
|
24,639 |
|
|
19,100 |
|
|
(1) LOE includes transportation and workover expenses.(2)
Adjusted EBITDAX is a non-GAAP financial measure. See below for
reconciliation to net income (loss).
CONTANGO OIL & GAS COMPANYCONDENSED CONSOLIDATED
BALANCE SHEETS(in thousands) |
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
|
|
2017 |
|
2016 |
|
|
|
|
|
|
|
ASSETS |
|
(unaudited) |
Cash
and cash equivalents |
|
$ |
— |
|
$ |
— |
Accounts receivable, net |
|
|
11,621 |
|
|
16,727 |
Other
current assets |
|
|
3,422 |
|
|
2,327 |
Net
property and equipment |
|
|
342,335 |
|
|
340,382 |
Investment in affiliates and other non-current assets |
|
|
18,790 |
|
|
17,078 |
|
|
|
|
|
|
|
TOTAL ASSETS |
|
$ |
376,168 |
|
$ |
376,514 |
|
|
|
|
|
|
|
LIABILITIES AND
SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
Accounts payable and
accrued liabilities |
|
|
45,699 |
|
|
55,135 |
Other
current liabilities |
|
|
6,140 |
|
|
7,754 |
Long-term debt |
|
|
71,316 |
|
|
54,354 |
Asset
retirement obligations |
|
|
18,592 |
|
|
22,618 |
Other
non-current liabilities |
|
|
248 |
|
|
248 |
Total
shareholders’ equity |
|
|
234,173 |
|
|
236,405 |
|
|
|
|
|
|
|
TOTAL LIABILITIES &
SHAREHOLDERS’ EQUITY |
|
$ |
376,168 |
|
$ |
376,514 |
CONTANGO OIL & GAS COMPANYCONSOLIDATED STATEMENTS
OF OPERATIONS(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited) |
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate sales |
|
$ |
6,483 |
|
|
$ |
6,971 |
|
|
$ |
12,025 |
|
|
$ |
12,218 |
|
Natural
gas sales |
|
|
11,135 |
|
|
|
9,337 |
|
|
|
22,275 |
|
|
|
19,272 |
|
Natural
gas liquids sales |
|
|
2,658 |
|
|
|
3,054 |
|
|
|
5,400 |
|
|
|
5,454 |
|
Total
revenues |
|
|
20,276 |
|
|
|
19,362 |
|
|
|
39,700 |
|
|
|
36,944 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
Operating
expenses |
|
|
6,329 |
|
|
|
7,020 |
|
|
|
13,162 |
|
|
|
14,624 |
|
Exploration expenses |
|
|
284 |
|
|
|
324 |
|
|
|
375 |
|
|
|
644 |
|
Depreciation, depletion and amortization |
|
|
12,714 |
|
|
|
17,875 |
|
|
|
24,485 |
|
|
|
34,420 |
|
Impairment and abandonment of oil and gas properties |
|
|
1,401 |
|
|
|
1,252 |
|
|
|
1,431 |
|
|
|
3,103 |
|
General
and administrative expenses |
|
|
5,833 |
|
|
|
5,384 |
|
|
|
12,429 |
|
|
|
11,286 |
|
Total
expenses |
|
|
26,561 |
|
|
|
31,855 |
|
|
|
51,882 |
|
|
|
64,077 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME
(EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
|
Gain from
investment in affiliates, net of income taxes |
|
|
166 |
|
|
|
1,295 |
|
|
|
1,950 |
|
|
|
1,335 |
|
Gain
(loss) from sale of assets |
|
|
(420 |
) |
|
|
— |
|
|
|
2,520 |
|
|
|
— |
|
Interest
expense |
|
|
(925 |
) |
|
|
(1,178 |
) |
|
|
(1,684 |
) |
|
|
(2,056 |
) |
Gain
(loss) on derivatives, net |
|
|
1,487 |
|
|
|
(4,381 |
) |
|
|
4,583 |
|
|
|
(177 |
) |
Other
income (expense) |
|
|
61 |
|
|
|
(270 |
) |
|
|
(27 |
) |
|
|
(310 |
) |
Total
other income (expense) |
|
|
369 |
|
|
|
(4,534 |
) |
|
|
7,342 |
|
|
|
(1,208 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS BEFORE INCOME
TAXES |
|
|
(5,916 |
) |
|
|
(17,027 |
) |
|
|
(4,840 |
) |
|
|
(28,341 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax
provision |
|
|
(118 |
) |
|
|
(269 |
) |
|
|
(309 |
) |
|
|
(359 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS |
|
$ |
(6,034 |
) |
|
$ |
(17,296 |
) |
|
$ |
(5,149 |
) |
|
$ |
(28,700 |
) |
Non-GAAP Financial Measures
EBITDAX represents net income (loss) before
interest expense, taxes, and depreciation, depletion and
amortization, and oil & gas expenses. Adjusted EBITDAX
represents EBITDAX as further adjusted to reflect the items set
forth in the table below, all of which will be required in
determining our compliance with financial covenants under our
credit facility.
We have included EBITDAX and Adjusted EBITDAX in
this release to provide investors with a supplemental measure of
our operating performance and information about the calculation of
some of the financial covenants that are contained in our credit
agreement. We believe EBITDAX is an important supplemental
measure of operating performance because it eliminates items that
have less bearing on our operating performance and so highlights
trends in our core business that may not otherwise be apparent when
relying solely on GAAP financial measures. We also believe
that securities analysts, investors and other interested parties
frequently use EBITDAX in the evaluation of companies, many of
which present EBITDAX when reporting their results. Adjusted
EBITDAX is a material component of the covenants that are imposed
on us by our credit agreement. We are subject to financial
covenant ratios that are calculated by reference to Adjusted
EBITDAX. Non-compliance with the financial covenants
contained in our credit agreement could result in a default, an
acceleration in the repayment of amounts outstanding and a
termination of lending commitments. Our management and
external users of our financial statements, such as investors,
commercial banks, research analysts and others, also use EBITDAX
and Adjusted EBITDAX to assess:
- the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
- the ability of our assets to generate cash sufficient to pay
interest costs and support our indebtedness;
- our operating performance and return on capital as compared to
those of other companies in our industry, without regard to
financing or capital structure; and
- the feasibility of acquisitions and capital expenditure
projects and the overall rates of return on alternative investment
opportunities.
EBITDAX and Adjusted EBITDAX are not
presentations made in accordance with generally accepted accounting
principles, or GAAP. As discussed above, we believe that the
presentation of EBITDAX and Adjusted EBITDAX in this release is
appropriate. However, when evaluating our results, you should
not consider EBITDAX and Adjusted EBITDAX in isolation of, or as a
substitute for, measures of our financial performance as determined
in accordance with GAAP, such as net income (loss). EBITDAX
and Adjusted EBITDAX have material limitations as performance
measures because they exclude items that are necessary elements of
our costs and operations. Because other companies may
calculate EBITDAX and Adjusted EBITDAX differently than we do,
EBITDAX may not be, and Adjusted EBITDAX as presented in this
release is not, comparable to similarly-titled measures reported by
other companies.
The following table reconciles net income to
EBITDAX and Adjusted EBITDAX for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
Net
loss |
|
$ |
(6,034 |
) |
|
$ |
(17,296 |
) |
|
$ |
(5,149 |
) |
|
$ |
(28,700 |
) |
Interest
expense |
|
|
925 |
|
|
|
1,178 |
|
|
|
1,684 |
|
|
|
2,056 |
|
Income
tax provision (benefit) |
|
|
118 |
|
|
|
269 |
|
|
|
309 |
|
|
|
359 |
|
Depreciation, depletion and amortization |
|
|
12,714 |
|
|
|
17,875 |
|
|
|
24,485 |
|
|
|
34,420 |
|
Exploration expense |
|
|
284 |
|
|
|
324 |
|
|
|
375 |
|
|
|
644 |
|
EBITDAX |
|
$ |
8,007 |
|
|
$ |
2,350 |
|
|
$ |
21,704 |
|
|
$ |
8,779 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss (gain) on derivative instruments |
|
$ |
(1,052 |
) |
|
$ |
6,629 |
|
|
$ |
(4,327 |
) |
|
$ |
3,932 |
|
Non-cash
stock-based compensation charges |
|
|
1,622 |
|
|
|
1,279 |
|
|
|
3,078 |
|
|
|
2,978 |
|
Impairment of oil and gas properties |
|
|
1,400 |
|
|
|
1,140 |
|
|
|
1,400 |
|
|
|
3,012 |
|
Loss
(gain) on sale of assets and investment in affiliates |
|
|
254 |
|
|
|
(1,295 |
) |
|
|
(4,470 |
) |
|
|
(1,335 |
) |
Adjusted
EBITDAX |
|
$ |
10,231 |
|
|
$ |
10,103 |
|
|
$ |
17,385 |
|
|
$ |
17,366 |
|
Drilling Activity Update
The derisking and development of our Southern
Delaware Basin acreage in Pecos County, Texas continued through the
second quarter. Specific highlights, through the date of this
release, were as follows:
Rude Ram
As previously disclosed, the Rude Ram #1H, our
second well in the Southern Delaware Basin, was drilled from a
common surface location with the Ripper State #1H targeting the
Upper Wolfcamp A. The well was completed in April 2017, and after
30 days of flowback, reached a maximum 24-hour IP rate of 1,304
Boed (69% oil) with a 30 day average rate of 1,065 Boed (68%
oil).
Ripper State
As previously disclosed, the Ripper State #1H
was drilled from a common surface location with the Rude Ram #1H,
targeting the Middle Wolfcamp A. The well was completed in April
2017, and after 30 days of flowback, reached a maximum 24-hour IP
rate of 1,131 Boed (73% oil) with a 30 day average rate of 806 Boed
(73% oil).
Gunner
The Gunner #2H was drilled to a TMD of 20,430
feet, including a 10,600 foot lateral, targeting the Lower Wolfcamp
A. The well has been completed with 50 stages of fracture
stimulation and we are currently drilling out the frac plugs to
initiate flowback, which is expected to begin in early
August.
Crusader and Fighting Ace
Both the Crusader #1H and Fighting Ace #1H were
spud in June 2017 from the same pad, allowing us to easily skid the
rig from one well to the other. The Crusader is currently
drilling at a measured depth of 11,139 feet. Once this well
is finished, we will skid back to the Fighting Ace and finish the
lateral section. Both wells will be drilled to a total
measured depth of approximately 20,000 feet, including a 10,000
foot lateral with 50 stages of frac. Completion operations on
both wells are expected to commence in late September, with initial
production expected in the fourth quarter.
Upon completion of these two wells, we expect to
move the rig to our seventh horizontal well, the Ragin Bull #1H,
which will be on the same pad as the Lonestar Gunfighter
well.
Management Commentary
Allan D. Keel, the Company’s President and Chief
Executive Officer, said “With three wells producing and three more
wells scheduled to come on-line soon, we continue to be encouraged
by the development of our Southern Delaware Basin acreage. With the
Gunner #2H well expected to commence production in early August,
our Fighting Ace #1H and Crusader #1H wells expected to commence
completion operations later this quarter, and our upcoming drilling
schedule, we have budgeted to have eight Southern Delaware Basin
wells on production by the end of the year.”
Guidance for Third Quarter 2017
The Company is providing the following guidance for the third
calendar quarter of 2017.
|
|
|
Production |
|
56,000 - 61,000 Mcfe per day |
|
|
|
LOE
(including transportation and workovers) |
|
$6.8 million - $7.3 million |
|
|
|
Production and ad valorem taxes (% of Revenue) |
|
4.00% |
|
|
|
|
Cash
G&A |
|
$4.5 million - $5.1 million |
|
|
|
DD&A Rate |
|
$2.30 - $2.55 |
Teleconference Call
Contango management will hold a conference call
to discuss the information described in this press release on
Thursday, August 3, 2017 at 9:30am Central Standard Time.
Those interested in participating in the earnings conference call
may do so by calling the following phone number: 1-888-737-3705,
(International 1-719-325-2170) and entering the following
participation code: 8587146. A replay of the call will
be available from Thursday, August 3, 2017 at 12:30pm CST through
Thursday, August 10, 2017 at 12:30pm CST by clicking on the audio
replay link here, and entering participation code 8587146.
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 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.
Contact:
Contango Oil & Gas Company
E. Joseph Grady – 713-236-7400
Senior Vice President and Chief Financial Officer
Sergio Castro – 713-236-7400
Vice President and Treasurer