|
|
ITEM 2.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
The following discussion and analysis should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes included in our Annual Report on Form 10-K and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.
Cautionary Note Regarding Forward-Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended ("the Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended ("the Exchange Act"). When used in this Quarterly Report, the words "could", "believe", "anticipate", "intend", "estimate", "expect", "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
All statements other than statements of historical facts included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and natural gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analysis made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including, general economic, market or business conditions; commodity prices; the opportunities (or lack thereof) that may be presented to and pursued by us; competitive actions by other oil and natural gas companies; adverse developments or losses from pending or future litigation and regulatory proceedings; our ability to identify, complete and integrate acquisitions of properties and businesses; changes in laws or regulations; adverse weather conditions and natural disasters such as hurricanes and other factors, including those listed under Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018, this Quarterly Report on Form 10-Q and in our other filings with the SEC, many of which are beyond our control and may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward‑looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward‑looking statements that we or persons acting on our behalf may issue
Except as otherwise required by applicable law, we disclaim any duty to update any forward‑looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report
Investors should note that Gulfport announces financial information in SEC filings, press releases and public conference calls. Gulfport may use the Investors section of its website (
www.gulfportenergy.com
) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on Gulfport’s website is not part of this Quarterly Report on Form 10-Q.
Overview
We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of natural gas, crude oil and natural gas liquids, or NGLs, in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal properties are located in the Utica Shale primarily in Eastern Ohio and the SCOOP Woodford and SCOOP Springer plays in Oklahoma. In addition, among other interests, we hold an acreage
position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC ("Grizzly"), and an approximate
21.8%
equity interest in Mammoth Energy Services, Inc. ("Mammoth Energy"), an energy services company listed on the Nasdaq Global Select Market (TUSK). We seek to achieve reserve growth and increase our cash flow through our annual drilling programs.
2019 Operational and Other Highlights
|
|
•
|
During the
six months ended June 30, 2019
, we spud
11
gross (
9.4
net) wells in the Utica Shale and participated in
three
additional gross (
0.8
net) wells that were drilled by other operators on our Utica Shale acreage. In addition, during the
six months ended June 30, 2019
, we spud
seven
gross (
5.7
net) wells in the SCOOP and participated in an additional
28
gross (
0.6
net) wells that were drilled by other operators on our SCOOP acreage. Of the
18
new wells we spud, at
June 30, 2019
, 16 were in various stages of completion and two were being drilled. In addition,
31
gross and net operated wells were turned-to-sales in our Utica Shale operating area and
nine
gross (
8.7
net) operated wells were turned-to-sales in our SCOOP operating area during the
six months ended June 30, 2019
.
|
|
|
•
|
For the
six months ended
June 30, 2019
, we decreased our unit general and administrative expense by
9%
to
$0.10
per Mcfe from
$0.11
per Mcfe for the
six months ended
June 30, 2018
.
|
|
|
•
|
In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400 million of our outstanding common stock within a 24 month period, which we believe underscores the confidence we have in our business model, financial performance and asset base. As of
July 26, 2019
, we have repurchased approximately
3.8 million
shares of our outstanding common stock pursuant to the plan for total consideration of approximately
$30.0 million
.
|
|
|
•
|
In December of 2018, we entered into an agreement to sell our non-core assets located in the WCBB and Hackberry fields of Louisiana to an undisclosed third party for a purchase price of approximately
$19.7 million
. We received approximately
$9.2 million
in cash and retained contingent overriding royalty interests. In addition, we could also receive contingent payments based on commodity prices exceeding certain thresholds over the next
two years
. The buyer has agreed to assume all plugging and abandonment liabilities associated with these assets. The effective date of the transaction is August 15, 2018. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions.
|
|
|
•
|
In July 2019, we used borrowings under our revolving credit facility to repurchase in the open market approximately
$104.4 million
aggregate principal amount of our outstanding 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes for
$80.3 million
.
|
2019 Production and Drilling Activity
During the three months ended
June 30, 2019
, our total net prod
uc
tion was
111,602,875
thousand cubic feet, or Mcf, of natural gas,
649,216
barrels of oil and
57,188,687
gallons of N
GLs for a total of
123,668
million cubic feet of natural gas equivalent, or MM
cfe, as compared to
108,236,412
Mcf of natural gas,
744,311
barrels of oil and
58,511,924
gallons of NGLs, or
121,061
MMcfe, for the three months ended
June 30, 2018
. Our total net production averaged approx
imately
1,359.0
MMcfe per day during the three months ended
June 30, 2019
, as compared to
1,330.3
MMcfe per day during the same period in
2018
. The
2%
increase
in production is largely the result of the continuing development of our Utica Shale and SCOOP acreage.
Utica Shale
. From January 1,
2019
through
June 30, 2019
, we spud
11
gross (
9.4
net) wells in the Utica Shale, of which
one
was being drilled and
ten
were in various stages of completion at
June 30, 2019
. We also participated in
three
additional gross (
0.8
net) wells that were drilled by other operators on our Utica Shale acreage. From
July 1, 2019
through
July 26, 2019
, we spud
two
gross (
2.0
net) well in the Utica Shale.
As of
July 26, 2019
, we had
one
operated horizontal rig running in the Utica Shale. We currently intend to spud
13
to
15
gross (
10
to
11
net) horizontal wells, and commence sales from
47
to
51
gross (
40
to
45
net) horizontal wells, on our Utica Shale acreage in 2019. We also anticipate an additional two to three net horizontal wells will be drilled, and sales commenced from two to three net horizontal wells, on our Utica Shale acreage by other operators during 2019.
Aggregate net production from our Utica Shale acreage during the
three months ended June 30, 2019
was approximately
95,616
MMcfe, or an average of
1,050.7
MMcfe per day, of which
97%
was natural gas and
3%
was oil and NGLs.
SCOOP
. From January 1,
2019
through
June 30, 2019
, we spud
seven
gross (
5.7
net) wells in the SCOOP, of which
one
was being drilled and
six
were in various stages of completion at
June 30, 2019
. We also participated in an additional
28
gross (
0.6
net) wells that were drilled by other operators on our SCOOP acreage. From
July 1, 2019
through
July 26, 2019
, we did not spud any wells on our SCOOP acreage.
As of
July 26, 2019
, we had
one
operated horizontal rig running on our SCOOP acreage. We currently intend to spud
nine
to
ten
gross (
seven
to
eight
net) horizontal wells, and commence sales from
15
to
17
gross (
14
to
15
net) horizontal wells, on our SCOOP acreage in 2019. We also anticipate one to two net wells will be drilled, and sales commenced from one to two net wells on our SCOOP acreage by other operators during 2019.
Aggregate net production from our SCOOP acreage during the
three months ended June 30, 2019
was approximately
27,149
MMcfe, or an average of
298.3
MMcfe per day, of which
71%
was from natural gas and
29%
was from oil and NGLs.
WCBB
. From January 1,
2019
through July 3, 2019, we did not spud any new wells or recomplete any wells in the WCBB field. Our aggregate net production from the WCBB field during the three months ended
June 30, 2019
was approximately
685
MMcfe, or an average of
7.5
MMcfe per day, all of which was from oil. On July 3, 2019, we closed on the sale of all of our WCBB assets.
East Hackberry Field
. From January 1,
2019
through July 3, 2019, we did not spud any new wells or recomplete any wells. Our aggregate net production from the East Hackberry field during the three months ended
June 30, 2019
was approximately
91.3
MMcfe, or an average of
1.0
MMcfe per day, all of which was from oil. On July 3, 2019, we closed on the sale of our East Hackberry assets.
West Hackberry Field
. From January 1,
2019
through July 3, 2019, we did not spud any new wells in our West Hackberry field. Our aggregate net production from the West Hackberry field during the
three months ended June 30, 2019
was approximately
17.0
MMcfe, or an average of
186.5
Mcfe per day, all of which was from oil. On July 3, 2019, we closed on the sale of our West Hackberry assets.
We have no further capital obligations related to the Louisiana fields after July 3, 2019.
Niobrara Formation
. From January 1,
2019
through
July 26, 2019
, there were no wells spud on our Niobrara Formation acreage. Aggregate net production was approximately
17.0
MMcfe, or an average of
187.0
Mcfe per day during the three months ended
June 30, 2019
, all of which was from oil.
Bakken
. As of
June 30, 2019
, we had an interest in 18 wells and overriding royalty interests in certain existing and future wells. Aggregate net production from this acreage during the three months ended
June 30, 2019
was approximately
92.5
MMcfe, or an average of
1.0
MMcfe per day, of which
77%
was from oil and
23%
was from natural gas and natural gas liquids.
RESULTS OF OPERATIONS
Comparison of the Three Month Periods Ended
June 30,
2019
and
2018
We reported net
income
of
$235.0 million
for the three months ended
June 30, 2019
as compared to net
income
of
$111.3 million
for the three months ended
June 30, 2018
. This
$123.7 million
period-to-period
increase
was due primarily to a
$206.3 million
increase in oil and natural gas revenues and a
$179.3 million
increase in income tax benefit, partially offset by a
$134.5 million
increase in loss from equity method investments, including a
$125.4 million
impairment related to our investment in Mammoth Energy and a $122.0 million decrease in gain on sale of equity method investments for the three months ended
June 30, 2019
as compared to the three months ended
June 30, 2018
. If Mammoth Energy's common stock continues to trade below our carrying value for a prolonged period of time, further impairment of our investment in Mammoth Energy may be necessary. The gain on sale of equity investments in 2018 was the result of the sale of our interest in Strike Force and the sale of Mammoth Energy common stock during 2018.
Natural Gas, Oil and NGL Revenues
. For the three months ended
June 30, 2019
, we reported oil and natural gas revenues of
$459.0 million
as compared to oil and natural gas revenues of
$252.7 million
during the same period in
2018
. This
$206.3 million
, or
82%
,
increase
in revenues was primarily attributable to the following:
|
|
•
|
A $241.7 million increase in natural gas, oil and condensate and NGLs sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $224.6 million was due to a favorable change in the fair value of our open derivative positions in each period and $17.1 million was due to favorable changes in settlements related to our derivative positions. The favorable change in fair value of our open derivative positions is primarily a result of the decrease in the forward curve prices for natural gas from the previous reporting period.
|
Such increases were partially offset by:
|
|
•
|
A
$12.4 million
decrease
in oil and condensate sales without the impact of derivatives due to a 14% decrease in oil and condensate market prices and a
13%
decrease
in oil and condensate sales volumes.
|
|
|
•
|
A
$15.6 million
decrease
in NGLs sales without the impact of derivatives due to a 36% decrease in NGLs market prices and a
2%
decrease
in NGLs sales volumes.
|
|
|
•
|
A
$7.4 million
decrease
in natural gas sales without the impact of derivatives due to a 6% decrease in natural gas market prices, partially offset by a
3%
increase
in natural gas sales volumes.
|
The following table summarizes our oil and condensate, natural gas and NGLs production and related pricing for the three months ended
June 30, 2019
, as compared to such data for the three months ended
June 30, 2018
:
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
2019
|
|
2018
|
|
($ In thousands)
|
Natural gas sales
|
|
|
|
Natural gas production volumes (MMcf)
|
111,603
|
|
|
108,236
|
|
|
|
|
|
Total natural gas sales
|
$
|
225,257
|
|
|
$
|
232,695
|
|
|
|
|
|
Natural gas sales without the impact of derivatives ($/Mcf)
|
$
|
2.02
|
|
|
$
|
2.15
|
|
Impact from settled derivatives ($/Mcf)
|
$
|
0.18
|
|
|
$
|
0.17
|
|
Average natural gas sales price, including settled derivatives ($/Mcf)
|
$
|
2.20
|
|
|
$
|
2.32
|
|
|
|
|
|
Oil and condensate sales
|
|
|
|
Oil and condensate production volumes (MBbls)
|
649
|
|
|
744
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and condensate sales
|
$
|
36,910
|
|
|
$
|
49,319
|
|
|
|
|
|
Oil and condensate sales without the impact of derivatives ($/Bbl)
|
$
|
56.85
|
|
|
$
|
66.26
|
|
Impact from settled derivatives ($/Bbl)
|
$
|
0.57
|
|
|
$
|
(10.97
|
)
|
Average oil and condensate sales price, including settled derivatives ($/Bbl)
|
$
|
57.42
|
|
|
$
|
55.29
|
|
|
|
|
|
NGLs sales
|
|
|
|
NGLs production volumes (MGal)
|
57,189
|
|
|
58,512
|
|
|
|
|
|
Total NGLs
|
$
|
25,687
|
|
|
$
|
41,271
|
|
|
|
|
|
NGLs sales without the impact of derivatives ($/Gal)
|
$
|
0.45
|
|
|
$
|
0.71
|
|
Impact from settled derivatives ($/Gal)
|
$
|
0.06
|
|
|
$
|
(0.07
|
)
|
Average NGLs sales price, including settled derivatives ($/Gal)
|
$
|
0.51
|
|
|
$
|
0.64
|
|
|
|
|
|
Natural gas, oil and condensate and NGLs sales
|
|
|
|
Natural gas equivalents (MMcfe)
|
123,668
|
|
|
121,061
|
|
|
|
|
|
Total natural gas, oil and condensate and NGLs sales
|
$
|
287,854
|
|
|
$
|
323,285
|
|
|
|
|
|
Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe)
|
$
|
2.33
|
|
|
$
|
2.67
|
|
Impact from settled derivatives ($/Mcfe)
|
$
|
0.19
|
|
|
$
|
0.05
|
|
Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe)
|
$
|
2.52
|
|
|
$
|
2.72
|
|
|
|
|
|
Production Costs:
|
|
|
|
Average production costs ($/Mcfe)
|
$
|
0.18
|
|
|
$
|
0.19
|
|
Average production taxes ($/Mcfe)
|
$
|
0.07
|
|
|
$
|
0.06
|
|
Average midstream gathering and processing ($/Mcfe)
|
$
|
0.58
|
|
|
$
|
0.59
|
|
Total production costs, midstream costs and production taxes ($/Mcfe)
|
$
|
0.83
|
|
|
$
|
0.84
|
|
Lease Operating Expenses
. Lease operating expenses ("LOE") not including production taxes decreased to
$22.4 million
for the three months ended
June 30, 2019
from
$22.9 million
for the three months ended
June 30, 2018
. This
$0.5 million
, or
2%
,
decrease
was primarily the result of a decrease in wireline services, production chemicals, contract labor and facility maintenance expense, partially offset by an increase in disposal costs, location repairs and ad valorem taxes. In
addition, d
ue to increased efficiencies and a
2%
increase
in our production volumes for the
three months ended June 30, 2019
as compared to the
three months ended June 30, 2018
, our per unit LOE decreased by
5%
from
$0.19
per Mcfe to
$0.18
per Mcfe.
Production Taxes
. Production taxes increased
$0.4 million
, or
5%
, to
$8.1 million
for the three months ended
June 30, 2019
from
$7.7 million
for the three months ended
June 30, 2018
. This
increase
was primarily due to an increase in production volumes and an increase in the production tax rate associated with our SCOOP production.
Midstream Gathering and Processing Expenses
. Midstream gathering and processing expenses increased to
$72.0 million
for the three months ended
June 30, 2019
from
$71.4 million
for the same period in
2018
. This
$0.6 million
, or
1%
,
increase
was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2018 and 2019 drilling activities.
Depreciation, Depletion and Amortization
. Depreciation, depletion and amortization ("DD&A") expense increased to
$125.0 million
for the three months ended
June 30, 2019
, and consisted of
$122.5 million
in depletion of oil and natural gas
properties and
$2.5 million
in depreciation of other property and equipment, as compared to total DD&A expense of
$121.9 million
for the three months ended
June 30, 2018
. This
$3.1 million
, or
3%
,
increase
was primarily due to an increase in our depletion rate as a result of a decrease in our full cost pool and a decrease in our total proved reserves volumes used to calculate our total DD&A expense, as well as an increase in our production.
General and Administrative Expenses
. Net general and administrative expenses decreased to
$13.3 million
for the three months ended
June 30, 2019
from
$14.0 million
for the three months ended
June 30, 2018
. This
$0.7 million
, or
5%
,
decrease
was primarily due to decreases in consulting fees and travel expense, partially offset by increases in computer support and tax services. In addition, for the
three months ended June 30, 2019
, we decreased our unit general and administrative expense by
8%
to
$0.11
per Mcfe from
$0.12
per Mcfe for the
three months ended June 30, 2018
.
Interest Expense
. Interest expense increased to
$34.9 million
for the three months ended
June 30, 2019
as compared to
$33.7 million
for the three months ended
June 30, 2018
due primarily to increased borrowings on our revolving credit facility as compared to the same period in 2018. In addition, total weighted average debt outstanding under our revolving credit facility was
$168.8 million
for the
three months ended June 30, 2019
as compared to
$112.9 million
debt outstanding under such facility. As of
June 30, 2019
, amounts borrowed under our revolving credit facility bore interest at a weighted average rate of
3.93%
. In addition, we capitalized approximately
$1.0 million
and
$1.5 million
in interest expense to undeveloped oil and natural gas properties during the three months ended
June 30, 2019
and
2018
, respectively. This $0.5 million decrease in capitalized interest in the 2019 period was primarily the result of changes to our development plan for our oil and natural gas properties.
Income Taxes
. As of
June 30, 2019
, we had a federal net operating loss carryforward of approximately
$920.4 million
from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. During the three months ending June 30, 2019, management determined there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards should be realized and recorded a discrete tax benefit of
$179.3 million
. We will recognize through the annual effective tax rate a projected release of valuation allowance of an additional $27.7 million with respect to current year earnings. We will maintain a valuation allowance of $4.8 million against the net deferred tax asset for certain tax attributes for which we have determined it is more likely than not those attribute carryforwards will expire prior to utilization.
Comparison of the Six Month Periods Ended
June 30,
2019
and
2018
We reported net
income
of
$297.2 million
for the
six months ended June 30, 2019
as compared to net
income
of
$201.4 million
for the
six months ended June 30, 2018
. This
$95.8 million
period-to-period
increase
was due primarily to a
$201.4 million
increase
in natural gas, oil and NGL revenues and a
$179.3 million
increase in income tax benefit, partially offset by a
$143.7 million
increase
in loss from equity method investments, including a
$125.4 million
impairment related to our investment in Mammoth Energy, a
$122.0 million
decrease in gain on sale of equity method investments, a
$10.5 million
increase in DD&A and a
$6.7 million
increase
in midstream gathering and processing expenses for the
six months ended
June 30, 2019
as compared to the
six months ended
June 30, 2018
. If Mammoth Energy's common stock continues to trade below our carrying value for a prolonged period of time, further impairment of our investment in Mammoth Energy may be necessary. The gain on sale of equity investments in 2018 was a result of the sale of our interest in Strike Force and the sale of Mammoth Energy common stock during 2018.
Oil and Gas Revenues
. For the
six months ended June 30, 2019
, we reported oil and natural gas revenues of
$779.6 million
as compared to oil and natural gas revenues of
$578.1 million
during the same period in
2018
. This
$201.4 million
, or
35%
,
increase
in revenues was primarily attributable to the following:
|
|
•
|
A $238.1 million increase in in natural gas, oil and condensate and NGLs sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $254.8 million was due to favorable changes in the fair value of our open derivative positions in each period, partially offset by a $16.7 million unfavorable change in settlements related to our derivative positions. The favorable change in fair value of our open derivative positions is primarily a result of the decrease in the forward curve prices for natural gas from the previous reporting period.
|
|
|
•
|
A
$19.2 million
increase
in natural gas sales without the impact of derivatives due to a
2%
increase
in natural gas sales volumes and a 2% increase in natural gas market prices.
|
Such increases were partially offset by:
|
|
•
|
A
$25.6 million
decrease
in oil and condensate sales without the impact of derivatives due to a
16%
decrease
in oil and condensate sales volumes and a 13% decrease in oil and condensate market prices.
|
|
|
•
|
A
$30.3 million
decrease
in NGLs sales without the impact of derivatives due to a 28% decrease in NGLs market prices and a
9%
decrease
in NGLs sales volumes.
|
The following table summarizes our oil and condensate, natural gas and NGLs production and related pricing for the
six months ended June 30, 2019
, as compared to such data for the
six months ended June 30, 2018
:
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
2019
|
|
2018
|
|
($ In thousands)
|
Natural gas sales
|
|
|
|
Natural gas production volumes (MMcf)
|
213,682
|
|
|
210,278
|
|
|
|
|
|
Total natural gas sales
|
$
|
501,273
|
|
|
$
|
482,094
|
|
|
|
|
|
Natural gas sales without the impact of derivatives ($/Mcf)
|
$
|
2.35
|
|
|
$
|
2.29
|
|
Impact from settled derivatives ($/Mcf)
|
$
|
(0.03
|
)
|
|
$
|
0.17
|
|
Average natural gas sales price, including settled derivatives ($/Mcf)
|
$
|
2.32
|
|
|
$
|
2.46
|
|
|
|
|
|
Oil and condensate sales
|
|
|
|
Oil and condensate production volumes (MBbls)
|
1,261
|
|
|
1,501
|
|
|
|
|
|
Total oil and condensate sales
|
$
|
69,392
|
|
|
$
|
95,005
|
|
|
|
|
|
Oil and condensate sales without the impact of derivatives ($/Bbl)
|
$
|
55.03
|
|
|
$
|
63.29
|
|
Impact from settled derivatives ($/Bbl)
|
$
|
0.31
|
|
|
$
|
(8.29
|
)
|
Average oil and condensate sales price, including settled derivatives ($/Bbl)
|
$
|
55.34
|
|
|
$
|
55.00
|
|
|
|
|
|
NGLs sales
|
|
|
|
NGLs production volumes (MGal)
|
113,019
|
|
|
124,268
|
|
|
|
|
|
Total NGLs sales
|
$
|
57,812
|
|
|
$
|
88,107
|
|
|
|
|
|
NGLs sales without the impact of derivatives ($/Gal)
|
$
|
0.51
|
|
|
$
|
0.71
|
|
Impact from settled derivatives ($/Gal)
|
$
|
0.04
|
|
|
$
|
(0.05
|
)
|
Average NGLs sales price, including settled derivatives ($/Gal)
|
$
|
0.55
|
|
|
$
|
0.66
|
|
|
|
|
|
Natural gas, oil and condensate and NGLs sales
|
|
|
|
Gas equivalents (MMcfe)
|
237,394
|
|
|
237,038
|
|
|
|
|
|
Total natural gas, oil and condensate and NGLs sales
|
$
|
628,477
|
|
|
$
|
665,206
|
|
|
|
|
|
Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe)
|
$
|
2.65
|
|
|
$
|
2.81
|
|
Impact from settled derivatives ($/Mcfe)
|
$
|
(0.01
|
)
|
|
$
|
0.06
|
|
Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe)
|
$
|
2.64
|
|
|
$
|
2.87
|
|
|
|
|
|
Production Costs:
|
|
|
|
Average production costs ($/Mcfe)
|
$
|
0.18
|
|
|
$
|
0.18
|
|
Average production taxes ($/Mcfe)
|
$
|
0.07
|
|
|
$
|
0.06
|
|
Average midstream gathering and processing ($/Mcfe)
|
$
|
0.60
|
|
|
$
|
0.57
|
|
Total production costs, midstream costs and production taxes ($/Mcfe)
|
$
|
0.85
|
|
|
$
|
0.81
|
|
Lease Operating Expenses
. Lease operating expenses not including production taxes increased to
$42.2 million
for the
six months ended June 30, 2019
from
$41.8 million
for the
six months ended June 30, 2018
. This
$0.4 million
, or
1%
,
increase
was primarily the result of an increase in expenses related to location repair, disposal costs and ad valorem taxes, partially offset by a decrease in wireline services, facility maintenance expense and surface rentals.
Production Taxes
. Production taxes increased to
$16.0 million
for the
six months ended June 30, 2019
from
$14.5 million
for the same period in
2018
. This
$1.5 million
, or
10%
,
increase
was primarily related to an increase in the production tax rate associated with our SCOOP production.
Midstream Gathering and Processing Expenses
. Midstream gathering and processing expenses increased to
$142.3 million
for the
six months ended June 30, 2019
from
$135.6 million
for the same period in
2018
. This
$6.7 million
, or
5%
,
increase
was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2018 and 2019 drilling activities as well as routine contract escalations associated with our Utica Shale production.
Depreciation, Depletion and Amortization
. Depreciation, depletion and amortization expense increased to
$243.4 million
for the
six months ended June 30, 2019
, and consisted of
$237.7 million
in depletion of oil and natural gas properties and
$5.7 million
in depreciation of other property and equipment, as compared to total DD&A expense of
$232.9 million
for the
six months ended June 30, 2018
. This
$10.5 million
, or
4%
,
increase
was primarily due to an increase in our depletion rate as a result of a decrease in our full cost pool and a decrease in our total proved reserves volumes used to calculate our total DD&A expense and an increase in our production.
General and Administrative Expenses
. Net general and administrative expenses decreased to
$24.8 million
for the
six months ended June 30, 2019
from
$27.1 million
for the
six months ended June 30, 2018
. This
$2.3 million
, or
8%
,
decrease
was primarily due to decreases in consulting fees and travel expenses, partially offset by increases in tax services and computer support. I
n addition,
for the
six months ended June 30, 2019
, we decreased our unit general and administrative expense by
9%
to
$0.10
per Mcfe from
$0.11
per Mcfe the
six months ended June 30, 2018
.
Interest Expense
. Interest expense increased to
$69.0 million
for the
six months ended June 30, 2019
from
$67.7 million
for the
six months ended June 30, 2018
due primarily to increased borrowings on our revolving credit facility. Total weighted average debt outstanding under our revolving credit facility was
$123.3 million
for the
six months ended June 30, 2019
as compared to
$100.1 million
for the same period in
2018
. Additionally, we capitalized approximately
$1.8 million
and
$2.4 million
in interest expense to undeveloped oil and natural gas properties during the
six months ended June 30, 2019
and
June 30, 2018
, respectively. This $0.6 million
decrease
in capitalized interest in the
2019
period was primarily the result of changes to our development plan for our oil and natural gas properties.
Income Taxes
. As of
June 30, 2019
, we had a federal net operating loss carryforward of approximately
$920.4 million
from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. During the six months ending June 30, 2019, management determined there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards should be realized and recorded a discrete tax benefit of
$179.3 million
. We will recognize through the annual effective tax rate a projected release of valuation allowance of an additional $27.7 million with respect to current year earnings. We will maintain a valuation allowance of $4.8 million against the net deferred tax asset for certain tax attributes for which we have determined it is more likely than not those attribute carryforwards will expire prior to utilization.
Liquidity and Capital Resources
Overview
.
Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or oil and natural gas production.
Net cash flow provided by operating activities was
$309.0 million
for the
six months ended June 30, 2019
as compared to
$411.0 million
for the same period in
2018
. This $102.0 million
decrease
was primarily the result of a decrease in cash receipts from our oil and natural gas purchasers due to an
8%
decrease
in net revenues after giving effect to settled derivative
instruments and an increase in our operating expenses. In addition, we received
$2.5 million
in dividends from our investment in Mammoth Energy during the six months ended June 30, 2019.
Net cash used in investing activities for the
six months ended June 30, 2019
was
$419.4 million
as compared to $
360.5 million
for the same period in
2018
. During the
six months ended June 30, 2019
, we spent
$417.5 million
in additions to oil and natural gas properties, of which $256.7 million was spent on our
2019
drilling and completion activities, $83.9 million was spent on expenses attributable to wells spud, completed and recompleted during
2018
, $25.8 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $27.8 million was spent on tubulars, with the remainder attributable mainly to future location development and capitalized general and administrative expenses. During the
six months ended June 30, 2019
, we invested
$0.4 million
in Grizzly and received a distribution of
$1.9 million
from Tatex. We did not make any investments in our other equity investments during the
six months ended June 30, 2019
.
Net cash provided by financing activities for the
six months ended June 30, 2019
was $
78.9 million
as compared to net cashed used in financing activities of $
30.9 million
for the same period in
2018
. The
2019
amount provided by financing activities is primarily attributable to net borrowings under our credit facility partially offset by purchases under our stock repurchase program of approximately
$30.0 million
.
Credit Facility.
We have entered into a senior secured revolving credit facility, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 13, 2021. As of
June 30, 2019
, we had a borrowing base of $1.4 billion, with an elected commitment of $1.0 billion, and
$155.0 million
in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of
$251.5 million
of outstanding letters of credit, were
$593.5 million
as of
June 30, 2019
. This facility is secured by substantially all of our assets. Our wholly owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings") and Mule Sky LLC ("Mule Sky") guarantee our obligations under our revolving credit facility.
Advances under our revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At
June 30, 2019
, amounts borrowed under our credit facility bore interest at
a weighted average rate of
3.93%
.
Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investment plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful dispositions will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than
4.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at
June 30, 2019
.
Senior Notes
.
In April 2015, we issued an aggregate of $350.0 million in principal amount of our Senior Notes due 2023 (the "2023 Notes"). Interest on these senior notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes will mature on May 1, 2023.
On October 14, 2016, we issued an aggregate of $650.0 million in principal amount of our Senior Notes due 2024 (the "2024 Notes"). Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024.
On December 21, 2016, we issued an aggregate of $600.0 million in principal amount of our Senior Notes due 2025 (the "2025 Notes"). Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025.
On October 11, 2017, we issued $450.0 million in aggregate principal amount of our Senior Notes due 2026 (the "2026 Notes" and, together with the 2023 Notes, the 2024 Notes, and the 2025 Notes, the "Notes"). Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026. We received approximately $444.1 million in net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all of our outstanding borrowings under our secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to our 2017 capital development plans.
All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings or Mule Sky, and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors’ secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the Notes.
If we experience a change of control (as defined in the senior note indentures relating to the Notes), we will be required to make an offer to repurchase the Notes and at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in our senior note indentures, we will be required to use the remaining proceeds to make an offer to repurchase the Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note indentures relating to the Notes contain certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. Under the indentures relating to the Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the Notes are ranked as “investment grade.”
In connection with the issuance of the 2024 Notes, 2025 Notes and 2026 Notes, we and our subsidiary guarantors entered into registration rights agreements, pursuant to which we agreed to file a registration statement with respect to offers to exchange the 2024 Notes, 2025 Notes and 2026 Notes, as applicable, for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and 2025 Notes were completed on September 13, 2017, and the exchange offer for the 2026 Notes was completed on March 22, 2018.
We may use a combination of cash and borrowings under our revolving credit facility to retire our outstanding debt, through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
Construction Loan.
On June 4, 2015, we entered into a construction loan agreement (the "construction loan") with InterBank for the construction of our new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The construction loan allows for maximum principal borrowings of $24.5 million and required us to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and we make monthly payments of interest and principal. The final payment is due June 4, 2025. As of
June 30, 2019
, the total borrowings under the construction loan were approxim
ately
$22.7 million
.
Capital Expenditures
.
Our recent capital commitments have been primarily for the execution of our drilling programs, for acquisitions in the Utica Shale and our SCOOP acquisition in 2017, and for investments in entities that may provide services to facilitate the development of our acreage. Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry conditions, (2) pursue acquisition and disposition opportunities and (3) pursue business integration opportunities.
Of our net reserves at
December 31, 2018
, 55.4% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities.
For further discussion on activities related to our capital expenditures incurred through June 30, 2019 see 2019 Production and Drilling Activity section above.
As of
June 30, 2019
, our net investment in Grizzly was approximately
$51.6
million. We do not currently anticipate any material capital expenditures in
2019
related to Grizzly’s activities.
We had no capital expenditures during the
six months ended June 30, 2019
related to our interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in
2019
.
In response to current declining forward natural gas prices, we are shifting to building an organization that is focused on disciplined capital allocation, cash flow generation and a commitment to executing a thoughtful, clearly communicated business plan that enhances value for all of our stockholders. We plan to maximize results with the core assets in our portfolio today and focus on returns that will allow us to operate within our cash flow in 2019. As a result, we currently expect to reduce our planned capital expenditures by approximately 29% as compared to 2018.
Our total capital expenditures for
2019
are currently estimated to be in the range of $525.0 million to $550.0 million for drilling and completion expenditures, with activity weighted to the first half of the year, of which $436.0 million was spent as of
June 30, 2019
. In addition, we currently expect to spend $40.0 to $50.0 million in
2019
for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale, of which
$23.2 million
was spent as of
June 30, 2019
. The
2019
range of capital expenditures is lower than the $814.7 million spent in
2018
, primarily due to the decrease in current commodity prices, specifically natural gas prices, and our desire to fund our capital development program within cash flow, as well as to generate free cash flow.
In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400 million of our outstanding common stock within a 24 month period. We intend to purchase shares under the repurchase program opportunistically with available funds primarily from cash flow from operations and sale of non-core assets while maintaining sufficient liquidity to fund our capital development programs.
We continually monitor market conditions and are prepared to adjust our drilling program if commodity prices dictate. Currently, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. We believe that
our strong liquidity position, hedge portfolio and conservative balance sheet position us well to react quickly to changing commodity prices and accelerate or decelerate our activity within the Utica Shale and the SCOOP as the market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels, our capital or other costs increase, our equity method investments require additional contributions and/or we pursue additional equity method investments or acquisitions, we may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us on acceptable terms or at all. Further, if we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. If the current low commodity price environment worsens, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.
Commodity Price Risk
See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for information regarding our open fixed price swaps at
June 30, 2019
.
Contractual and Commercial Obligations
We have various contractual obligations in the normal course of our operations and financing activities. There have been no material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended
December 31, 2018
.
Off-balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of
June 30, 2019
, our material off-balance sheet arrangements and transactions include
$251.5 million
in letters of credit outstanding against our 2019 revolving credit facility and
$73.9 million
in surety bonds issued as financial assurance on midstream firm transportation agreements. Management believes these items will expire without being funded. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 7 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Critical Accounting Policies and Estimates
As of
June 30, 2019
, there have been no significant changes in our critical accounting policies from those disclosed in our 2018 Annual Report on Form 10-K.
New Accounting Pronouncements
In February 2016, the FASB issued Accounting Standards Update ("ASU") No.
2016-02
,
Leases (Topic 842)
.
The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. Subsequent to ASU 2016-02, the FASB issued several related ASU’s to clarify the application of the lease standard. We adopted the new standard as of
January 1, 2019
on a prospective basis using the simplified transition method permitted by ASU 2018-11,
Leases (Topic 842): Targeted Improvements.
The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. See Note 12 to our consolidated financial statements for further discussion of the lease standard.
In
June 2016
, the FASB issued ASU No.
2016-13
,
Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments
. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. Additionally, in
May 2019
, the FASB issued ASU No.
2019-05
,
Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief
. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoption of
2016-13
. The guidance is effective for periods after December 15, 2019, with early adoption permitted. We are currently evaluating the
impact this standard will have on our financial statements and related disclosures and do not anticipate it to have a material effect.
In
February 2018
, the FASB issued ASU No.
2018-02
,
Income statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
, which allows a reclassification from accumulated other comprehensive income to retained earnings for standard tax effects resulting from the Tax Cuts and Jobs Act of 2017. The amendment will be effective for reporting periods beginning after
December 15, 2018
, and early adoption is permitted. We assessed the impact of the ASU on our consolidated financial statements and related disclosures, and determined there was no material impact.
In
August 2018
, the FASB issued ASU No.
2018-13
,
Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement
which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after
December 15, 2019
, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures.
In
August 2018
, the FASB also issued ASU No.
2018-15
,
Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract
, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after
December 15, 2019
, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures.
In
November 2018
, the FASB also issued ASU No.
2018-18
,
Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606
, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after
December 15, 2019
, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures.