ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying unaudited condensed consolidated financial statements as of
June 30, 2017
and for the
nine months ended
June 30, 2017
and
2016
included in this report and with our Annual Report on Form 10-K for the fiscal year ended
September 30, 2016
. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2016
and elsewhere in this report. See “Forward-Looking Statements” below.
OVERVIEW
Financial and operating results for the
three and nine months ended
June 30, 2017
and
2016
, include:
|
|
•
|
Operating revenues totaling
$117 million
and
$442 million
on
337
and
984
operating days for the
three and nine months ended
June 30, 2017
, respectively, as compared to operating revenues of
$228 million
and
$832 million
on
778
and
1,570
operating days for the
three and nine months ended
June 30, 2016
, respectively;
|
|
|
•
|
Net loss of
$4 million
and
$24 million
for the
three and nine months ended
June 30, 2017
, respectively, as compared to net income of
$100 million
and
$261 million
for the
three and nine months ended
June 30, 2016
, respectively;
|
|
|
•
|
Capital expenditures of
$173 million
for the
nine months ended
June 30, 2017
, as compared to capital expenditures of
$198 million
for the
nine months ended
June 30, 2016
; and
|
|
|
•
|
Increase in cash on hand of
$329 million
for the
nine months ended
June 30, 2017
to
$474 million
.
|
Merger Agreement
On May 29, 2017, the Company entered into the Merger Agreement with Ensco and Merger Sub, pursuant to which Ensco will acquire the Company in an all-stock transaction. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
MARKET OUTLOOK
Industry Conditions
The level of activity in the offshore drilling industry, which affects the sector's profitability, is cyclical and highly dependent on the offshore capital expenditure levels of exploration and production ("E&P") companies. In turn, E&P company offshore drilling expenditures are influenced by the current prices of oil and gas, expectations about future prices, company-specific cash flow levels, historical project returns and other capital allocation strategies (e.g., onshore versus offshore drilling).
The offshore drilling industry remains in the midst of a very severe downturn that began in the second half of calendar year 2014. Since that time, the industry has experienced declining demand for drilling rigs that has been exacerbated by a sharp decline in oil prices. E&P companies generally reduced their offshore capital spending in 2015 and 2016 by canceling or deferring planned drilling programs, and this trend is expected to continue into the second half of calendar year 2017. Since declining to multi-year lows below $30 per barrel in early 2016, Brent oil prices recovered modestly during the latter part of 2016 and ranged between $46 and $52 per barrel in July 2017. We expect offshore rig demand to remain flat or decline from current levels during the remainder of calendar year 2017. Declines in offshore drilling demand and the associated reductions in rig utilization and day rates could materially and adversely affect our financial position, results of operation or cash flows. See "Our business depends on the level of activity in the oil and natural gas industry, which is significantly impacted by the volatility in oil and natural gas prices" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2016
.
Even as offshore rig demand declined from the peak levels in calendar year 2014, some drilling contractors continued to take delivery of new, more capable rigs that were ordered prior to the industry downturn. However, over the past year, drilling contractors have generally delayed further rig deliveries, especially for uncontracted rigs, through renegotiation of terms with the shipyards that are constructing these rigs. Due to the confluence of an oversupply of offshore rigs and declining rig demand, a lower percentage of marketed rigs are being re-contracted, and day rates and utilization have declined sharply across all offshore rig classes. While
clients generally prefer newer, high specification rigs over older, less capable rigs, many newer floaters and jackups have been idled or cold-stacked as drilling demand has declined across all regions, water depths and rig classes. The bifurcation trend of higher utilization rates for newer, more capable rigs has been generally muted, but has been maintained more consistently for floaters than for jackups.
Due to the uncertain duration of the current industry downturn, a growing number of older, less capable rigs have been permanently removed from the marketed supply of rigs by virtue of being scrapped, announced for scrapping, or cold stacked. Even with the permanent removal of approximately
46
ultra-deepwater and deepwater floaters and
35
jackups (including high and standard specification rigs) from the supply stack since the beginning of calendar year 2016, further declines in rig utilization and day rates are possible due to the persistent oversupply of offshore rigs relative to demand.
Consistent with our policy, we evaluate our drilling rigs and related equipment for impairment whenever events or changes in circumstances indicate the carrying value of these assets may exceed the estimated future net cash flows. Our evaluation, among other things, includes a review of external market factors and an assessment on the future marketability of a specific drilling unit. Further declines in offshore drilling demand, and/or a lack of improvement in drilling activity or day rates, may result in potential impairments to our drilling rigs and related equipment in the future. See "We may be required to record impairment charges with respect to our rigs" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2016
.
A current trend of some E&P companies to cancel, renegotiate, or repudiate existing drilling contracts has continued into 2017. In January 2017, the client for the
Atwood Achiever
exercised its option provided as part of a “blend and extend” agreement negotiated with the client in October 2015 to revert the contract to the original operating day rate and original contract end date.
Some of our contracts with clients may be canceled at the option of the client upon payment of a termination fee which may not fully compensate us for the loss of the contract and may result in a rig being idled for an extended period of time. In addition, some of our clients could experience liquidity or solvency issues or could otherwise be unable or unwilling to perform under a contract, which could ultimately lead a client to enter bankruptcy or otherwise encourage a client to seek to repudiate, cancel or renegotiate a contract. Further deterioration in cash flow generation by E&P companies may accelerate these trends. If our clients seek to cancel or renegotiate our significant contracts and we are unable to negotiate favorable terms or secure new contracts on substantially similar terms, or at all, our revenues and profitability could be materially reduced. See "Our business may experience reduced profitability if our clients terminate or seek to renegotiate our drilling contracts" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2016
.
Ultra-deepwater and Deepwater Rig Markets
Both the ultra-deepwater and deepwater rig markets have experienced declining demand, utilization and day rates since the second half of calendar year 2014. As of
July 6, 2017
,
87
ultra-deepwater rigs were under contract industry-wide (versus
104
on
July 6, 2016
) representing
69%
utilization of a total of
127
actively marketed rigs. The number of marketed deepwater rigs under contract
decreased
to
19
(from
20
on
July 6, 2016
), which represents
59%
utilization of the
32
active rigs. Declines in the percentage of marketed rigs under contract have been driven by reduced rig demand across all geographic regions coupled with an increase in marketed supply due to deliveries of newbuild rigs, primarily from South Korean and Singaporean shipyards.
As of
July 6, 2017
,
30
ultra-deepwater floaters were under construction with scheduled deliveries through April 2021,
eight
of which were contracted. However, this figure includes
six
floaters under long-term contracts with Petrobras, some or all of which may be delayed, repudiated, or canceled. In response to reduced rig demand and lack of suitable drilling programs, we and other drilling contractors have delayed delivery of uncontracted ultra-deepwater rigs under construction.
Ten
ultra-deepwater rigs are scheduled for delivery during the remainder of calendar year 2017 and an additional
20
units are scheduled for delivery in calendar year 2018 and beyond.
The number of offshore floaters permanently removed from the marketed supply of rigs has continued to increase due to the challenging market conditions. Since the beginning of calendar year 2016,
28
ultra-deepwater rigs and
18
deepwater rigs were announced for cold-stacking, retirement or scrapping and are no longer being actively marketed. Further attrition of marketed supply may continue during the remainder of calendar year 2017.
Our Ultra-deepwater Rigs and Deepwater Rigs
The
Atwood Achiever,
a dynamically positioned, ultra-deepwater drillship, is operating offshore Northwest Africa and currently contracted through November 2018. In January 2017, our client exercised its option to revert the contract to its original day rate and original contract end date of November 2017. Under the existing contract the current well in progress is estimated to be completed in January 2018.
The
Atwood Advantage
, a dynamically positioned, ultra-deepwater drillship, completed its drilling contract in the Mediterranean Sea on July 31, 2017. The rig is scheduled to be idled quayside in Spain.
The
Atwood Condor
, a dynamically positioned, ultra-deepwater semisubmersible, is quayside in Singapore, where it is undergoing maintenance and project preparation activities prior to commencing drilling services for a development drilling program in Australia scheduled to begin in January 2018.
The
Atwood Osprey
, an ultra-deepwater semisubmersible, is in Australia and transiting to commence a one well contract in August 2017 that is estimated to continue until November 2017. The rig also has a contract beginning in March 2018 for an expected duration of approximately 100 days.
The
Atwood Eagle
is currently idle in Singapore and is no longer being actively marketed for a new drilling contract. On May 5, 2017, we executed a sale and recycling agreement with respect to the
Atwood Eagle
, pursuant to which the vessel, together with associated equipment and machinery, will be sold to a third party to be demolished and recycled. We expect that the sale of the rig will be finalized in September 2017. See Note 4 to the Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
The
Atwood Admiral
and
Atwood Archer
are DP-3 dynamically-positioned, dual derrick, ultra-deepwater drillships rated to operate in water depths up to 12,000 feet and are currently under construction at the DSME shipyard in South Korea. These drillships will have enhanced technical capabilities, including two seven-ram BOPs, three 100-ton knuckle boom cranes, a 165-ton active heave “tree-running” knuckle boom crane and 200 person accommodations. Total cost, including project management, drilling and handling tools and spares, is approximately
$635 million
per drillship.
The
Atwood Admiral
and
Atwood Archer
were originally scheduled to be delivered in March 2015 and December 2015, respectively. Due to lack of suitable drilling programs, we have not yet secured the initial drilling contracts for these rigs. In December 2016, we entered into an amendment to delay the required delivery date of these two rigs to
September 30, 2019
and
June 30, 2020
, respectively. We are unable to provide any assurance that we will obtain drilling contracts for these rigs prior to their delivery. See “Risks Related to our Business will be adversely affected if we are unable to secure contracts on economically favorable terms” under Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2016
. Also, see Note 4 to our Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report for further details regarding the remaining payments to be made with respect to these two drillships.
Jackup Rig Market
The jackup market is experiencing similar utilization, demand and day rate challenges as the floater market. Declining rig demand coupled with delivery of newbuild rigs, primarily from shipyards in China and Singapore, has negatively impacted the jackup rig supply and demand balance worldwide. In the current market downturn, all classes of jackup rigs have experienced lower day rates and utilization. The bifurcation trend that has historically favored utilization of new, higher specification jackups at the expense of older, lower specification jackups is generally not being maintained as clients have become much more price sensitive and are drilling fewer technically challenging wells. As of
July 6, 2017
, the percentage of marketed high specification jackup rigs (i.e., rigs equal to or greater than 350-foot water depth capability) under contract was approximately
65%
, as compared to
67%
for the remainder of the global jackup fleet.
We expect that the potential for further increases in global jackup supply due to delivery of high specification newbuild rigs may apply additional pressure on jackup rig utilization and day rates. As of
July 6, 2017
, there were
99
newbuild jackup rigs under construction (versus
117
on
July 6, 2016
), most of which are being constructed in China and many of which are owned by speculators or the constructing shipyards. Of the
27
jackup rigs scheduled for delivery in the remainder of calendar year 2017, only
one
is contracted, while the remaining
98
rigs are scheduled for delivery primarily in calendar year 2018 and beyond. Similar to what has occurred with newbuild floaters, many of these scheduled jackup deliveries are expected to be delayed and/or canceled. Absent a strong recovery in high specification jackup rig demand and/or a significant reduction in jackup rig supply due to cold-stacking, scrapping or retirements, the marketed supply of jackups is likely to exceed client requirements throughout calendar year 2017.
Through
July 6, 2017
,
14
high specification jackups and
21
standard jackups have been cold-stacked, scrapped or retired since the beginning of calendar year 2016. Marketed supply attrition may continue throughout calendar year 2017.
Our High Specification Jackup Rigs
The
Atwood Mako
and
Atwood Manta,
both 400-foot water depth Pacific Class jackup rigs, operated offshore Vietnam through September 2015 and offshore Thailand through October 2015, respectively. Both
were idled in the Philippines in October 2015 after they completed their contracts and were unable to obtain follow-on work. The
Atwood Beacon
, a 400-foot water depth jackup, completed operations in the Mediterranean Sea in August 2016 and is currently idle in Malta. The
Atwood Aurora
, a 350-foot water depth jackup, completed operations offshore West Africa in September 2016 and is also idle in Malta. We continue to actively market these four high-specification jackup rigs while they are idle.
The
Atwood Orca,
a 400-foot water depth Pacific Class jackup
completed operations in offshore Thailand in October 2016 and was subsequently idled in Singapore where it underwent maintenance and project preparation activities. In January 2017, the rig entered into a one-year contract in Thailand which commenced in April 2017.
Contract Backlog
We maintain a backlog of commitments for contract drilling revenues. Our contract backlog as of
June 30, 2017
was approximately
$293 million
representing a
70%
decrease
compared to our contract backlog of
$1.0 billion
as of
June 30, 2016
primarily due to realization of contract backlog. We calculate our contract backlog by multiplying the day rate under our drilling contracts by the number of days remaining under the contract, assuming full utilization. The calculation does not include any revenues related to mobilization, demobilization, contract preparation, reimbursable items or bonuses. The amount of actual revenues earned and the actual periods during which revenues are earned will be different from the amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including newbuild rig delivery dates, client elected standby periods, unscheduled repairs, maintenance requirements, weather delays and other factors. Such factors may result in lower applicable day rates than the full contractual day rate and/or delays in receiving the full contractual operating rate. In addition, under certain circumstances, our clients may seek to terminate, repudiate or renegotiate our contracts, which could have the effect of reducing our contract backlog. See “Risks Related to our Business-Our business may experience reduced profitability if our clients terminate, repudiate, or renegotiate our drilling contracts” and "Our current backlog of contract drilling revenue may not be fully realized, and the periods which revenues are earned may vary" under Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2016
.
The following tables set forth the amount of our contract drilling revenue backlog and the percentage of available operating days committed for our fleet, excluding drilling units under construction and the
Atwood Eagle.
On May 5, 2017, we executed a sale and recycling agreement with respect to the
Atwood Eagle
, pursuant to which the vessel, together with associated equipment and machinery will be sold to a third party to be demolished and recycled. See Note 4 to the Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling Revenue Backlog
1
|
Remaining Fiscal 2017
|
|
Fiscal 2018
|
|
Fiscal 2019
|
|
Fiscal 2020
|
|
Fiscal 2021
|
|
Total
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-deepwater
2
|
$
|
104
|
|
|
$
|
110
|
|
|
$
|
64
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
278
|
|
Jackups
|
5
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15
|
|
Total
|
$
|
109
|
|
|
$
|
120
|
|
|
$
|
64
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Available Operating Days Committed
1
|
Remaining Fiscal 2017
|
|
Fiscal 2018
|
|
Fiscal 2019
|
|
Fiscal 2020
|
|
Fiscal 2021
|
Ultra-deepwater
2
|
83
|
%
|
|
33
|
%
|
|
14
|
%
|
|
—
|
%
|
|
—
|
%
|
Jackups
|
20
|
%
|
|
11
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
Total
|
43
|
%
|
|
21
|
%
|
|
6
|
%
|
|
—
|
%
|
|
—
|
%
|
1
With the sale of the
Atwood Eagle
, the Company no longer operates deepwater drilling rigs and as such, the Deepwater classification has been removed from the tables above.
2
See Note 2 for recent contract activity included in contract backlog.
RESULTS OF OPERATIONS
Revenues—
Revenues for the
three and nine months ended
June 30, 2017
decreased
approximately
$111 million
and
$390 million
, or
49%
and
47%
, respectively, as compared to the
three and nine months ended
June 30, 2016
. An analysis of revenues by rig category is as follows:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
Three Months Ended June 30,
|
Nine Months Ended June 30,
|
(In millions)
|
2017
|
|
2016
|
|
Variance
|
|
2017
|
|
2016
|
|
Variance
|
Ultra-Deepwater
|
$
|
109
|
|
|
$
|
182
|
|
|
$
|
(73
|
)
|
|
$
|
419
|
|
|
$
|
553
|
|
|
$
|
(134
|
)
|
Deepwater
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
131
|
|
|
(131
|
)
|
Jackups
|
3
|
|
|
36
|
|
|
(33
|
)
|
|
5
|
|
|
111
|
|
|
(106
|
)
|
Reimbursable
|
5
|
|
|
10
|
|
|
(5
|
)
|
|
18
|
|
|
37
|
|
|
(19
|
)
|
|
$
|
117
|
|
|
$
|
228
|
|
|
$
|
(111
|
)
|
|
$
|
442
|
|
|
$
|
832
|
|
|
$
|
(390
|
)
|
Our ultra-deepwater fleet realized average revenues of $399,000 per day on 273 operating days for the
three months ended
June 30, 2017
, as compared to $500,000 per day on 364 operating days for the
three months ended
June 30, 2016
. The ultra-deepwater fleet realized average revenues of $470,000 per day on 892 operating days, as compared to $514,000 per day on 1,076 operating days for the
nine months ended
June 30, 2017
and
2016
, respectively. The decrease in total revenues for the three months ended June 30, 2017 was primarily due to the
Atwood Condor
completing its drilling contract in January 2017, after which the rig underwent planned maintenance and commenced its mobilization to Australia. Additionally, the
Atwood Osprey
earned lower revenue due to a lower contracted day rate in 2017. Lastly, the
Atwood Advantage
earned lower revenue due to unplanned repairs to subsea well control equipment. For the nine months ended June 30, 2017, revenues were lower primarily due to the
Atwood Condor
completing its drilling contract in January 2017, and the
Atwood Osprey
earning a lower contracted day rate as compared to the nine months ended June 30, 2016.
Our deepwater fleet did not operate in the
three and nine months ended
June 30, 2017
nor in the
three months ended
June 30, 2016
. During the
nine months ended
June 30, 2016
, our deepwater fleet realized average revenues of $426,000 per day on 307 operating days. The decrease in operating days and revenue is primarily due to the
Atwood Falcon
and
Atwood Eagle
completing their contracts in fiscal year 2016. The
Atwood Falcon
was idled and subsequently sold for recycling purposes, while the
Atwood Eagle
’s contract was suspended and the remaining term transferred to the
Atwood Osprey.
The
Atwood Eagle
was subsequently idled in Singapore. On May 5, 2017, we executed a sale and recycling agreement with respect to the
Atwood Eagle
, pursuant to which the vessel, together with associated equipment and machinery will be sold to a third party to be demolished and recycled. See Note 4 to the Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
Our jackup fleet realized average revenues of $47,000 per day on 64 operating days for the
three months ended
June 30, 2017
, as compared to $132,000 per day on 270 operating days for the
three months ended
June 30, 2016
. The jackup fleet realized average revenues of $55,000 per operating day on 92 operating days for the
nine months ended
June 30, 2017
, as compared to $135,000 per operating day on 821 operating days for the
nine months ended
June 30, 2016
. The jackup fleet realized lower revenue and operating days for the
nine months ended
June 30, 2017
, as compared to the
nine months ended
June 30, 2016
primarily due to the completion of the drilling contracts of the fleet in prior fiscal year. The
Atwood Orca
operated for 28 days during the three months ended December 31, 2016, and was subsequently idled. In January 2017, the rig entered into a one-year contract in Thailand and commenced operations in April 2017.
Revenue related to reimbursable expenses is primarily driven by our clients’ requests for equipment, fuel, services and/or personnel that are not included in the contractual operating day rate. Thus, these revenues vary depending on the timing of the clients’ requests and the work performed. Additionally, as a result of a number of our rigs being idled, reimbursable revenue naturally declines while the rigs remain un-contracted. Changes in the amount of revenue related to reimbursable expenses generally do not have a material effect on our financial position, results of operations, or cash flows.
Drilling Costs—
Drilling costs for the
three and nine months ended
June 30, 2017
decreased
approximately
$35 million
and
$131 million
or
41%
and
40%
, respectively, as compared to the
three and nine months ended
June 30, 2016
. An analysis of contract drilling costs by rig category is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONTRACT DRILLING COSTS
|
|
Three Months Ended June 30,
|
|
Nine Months Ended June 30,
|
(In millions)
|
2017
|
|
2016
|
|
Variance
|
|
2017
|
|
2016
|
|
Variance
|
Ultra-Deepwater
|
$
|
43
|
|
|
$
|
54
|
|
|
$
|
(11
|
)
|
|
$
|
146
|
|
|
$
|
168
|
|
|
$
|
(22
|
)
|
Deepwater
|
—
|
|
|
10
|
|
|
(10
|
)
|
|
1
|
|
|
71
|
|
|
(70
|
)
|
Jackups
|
7
|
|
|
16
|
|
|
(9
|
)
|
|
32
|
|
|
62
|
|
|
(30
|
)
|
Reimbursable
|
3
|
|
|
5
|
|
|
(2
|
)
|
|
15
|
|
|
23
|
|
|
(8
|
)
|
Other
|
(2
|
)
|
|
1
|
|
|
(3
|
)
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
$
|
51
|
|
|
$
|
86
|
|
|
$
|
(35
|
)
|
|
$
|
193
|
|
|
$
|
324
|
|
|
$
|
(131
|
)
|
Ultra-deepwater drilling costs decreased for the
three and nine months ended
June 30, 2017
, as compared to the
three and nine months ended
June 30, 2016
. Average drilling costs per calendar day for our ultra-deepwater rigs decreased from approximately $148,000 for the
three months ended
June 30, 2016
to approximately $117,000 for the
three months ended
June 30, 2017
, and from $153,000 for the
nine months ended
June 30, 2016
to $134,000 for the
nine months ended
June 30, 2017
. The drilling costs for our ultra-deepwater rigs were lower primarily due to the
Atwood Condor
completing its drilling contract in January 2017, after which the rig underwent planned maintenance and commenced its mobilization to Australia. Additionally, drilling costs on the
Atwood Osprey
were lower in 2017 due to cost savings initiatives executed on payroll and maintenance costs.
Our deepwater fleet did not operate in the
three and nine months ended
June 30, 2017
, as compared to
three and nine months ended
June 30, 2016
, during which drill costs of approximately $96,000 and $151,000, respectively, were incurred. This decrease is due to contract completions on the
Atwood Falcon
and
Atwood Eagle
in fiscal year 2016. The
Atwood Falcon
was subsequently sold for recycling purposes in 2016, while the
Atwood Eagle
was idled after its drilling contract was suspended and transferred to the
Atwood Osprey.
On May 5, 2017, we executed a sale and recycling agreement with respect to the
Atwood Eagle
, pursuant to which the vessel, together with associated equipment and machinery will be sold to a third party to be demolished and recycled. See Note 4 to the Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
Jackup drilling costs decreased for the
three and nine months ended
June 30, 2017
, as compared to the
three and nine months ended
June 30, 2016
, primarily due to the jackup fleet completing its drilling contracts and being subsequently idled in prior years. The average drilling cost per calendar day decreased from approximately $35,000 for the
three months ended
June 30, 2016
to approximately $15,000 for the
three months ended
June 30, 2017
, and from $45,000 for the
nine months ended
June 30, 2016
to $24,000 for the
nine months ended
June 30, 2017
.
Reimbursable costs are primarily driven by our clients’ requests for equipment, fuel, services and/or personnel that are not typically included in the contractual operating day rate. Thus, these costs vary depending on the timing of the clients’ requests and the work performed. Additionally, as a result of a number of our rigs being idled, reimbursable costs naturally decline while the rigs remain uncontracted. Changes in the amount of reimbursable costs generally do not have a material effect on our financial position, results of operations or cash flows.
Depreciation
—Depreciation for the
three and nine months ended
June 30, 2017
decreased
approximately
$3 million
and
$4 million
or
7%
and
3%
, respectively, as compared to the
three and nine months ended
June 30, 2016
. Depreciation was lower in 2017 due to the impairment of the
Atwood Eagle
, and the subsequent decision to enter into an agreement to recycle the rig in the third quarter of 2017. An analysis of depreciation expense by rig category is as follows:
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DEPRECIATION EXPENSE
|
|
Three Months Ended June 30,
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|
Nine Months Ended June 30,
|
(In millions)
|
2017
|
|
2016
|
|
Variance
|
|
2017
|
|
2016
|
|
Variance
|
Ultra-Deepwater
|
$
|
29
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|
|
$
|
29
|
|
|
$
|
—
|
|
|
$
|
86
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|
|
$
|
87
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|
|
$
|
(1
|
)
|
Deepwater
|
—
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|
|
2
|
|
|
(2
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)
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6
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|
|
7
|
|
|
(1
|
)
|
Jackups
|
8
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|
|
9
|
|
|
(1
|
)
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25
|
|
|
25
|
|
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—
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Other
|
1
|
|
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1
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|
|
—
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|
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4
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|
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6
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|
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(2
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)
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|
$
|
38
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|
|
$
|
41
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|
|
$
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(3
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)
|
|
$
|
121
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|
|
$
|
125
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|
|
$
|
(4
|
)
|
Asset Impairment—
During the
nine months ended
June 30, 2017
, we recorded a non-cash impairment charge of approximately
$59.2 million
(
$57.8 million
, net of tax, or
$0.72
per diluted share) to write the
Atwood Eagle
and its inventory of materials and supplies down to their approximate salvage value. On May 5, 2017, we executed a sale and recycling agreement with respect to the
Atwood Eagle
, pursuant to which the vessel, together with associated equipment and machinery will be sold to a third party to be demolished and recycled. See Note 4 to the Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
During the
nine months ended
June 30, 2016, we recorded a non-cash impairment charge of approximately
$64.7 million
(
$64.7 million
, net of tax, or
$1.00
per diluted share) to write the
Atwood Falcon
and its inventory of materials and supplies down to their approximate salvage value. See Note 4 to Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
General and Administrative—
For the
three and nine months ended
June 30, 2017
, general and administrative expenses increased by approximately
$3.6 million
and
$4.5 million
to
$15.6 million
and
$43.2 million
, respectively, as compared to
$12.0 million
and
$38.7 million
, respectively, for the
three and nine months ended
June 30, 2016
. The increase is primarily due to transaction costs related to the potential Merger with Ensco. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
Interest Expense, net of capitalized interest—
For the
three and nine months ended
June 30, 2017
, interest expense, net of capitalized interest,
decreased
by approximately
$6.1 million
and
$7.0 million
to
$13.6 million
and
$43.5 million
, respectively, as compared to
$19.7 million
and
$50.5 million
, respectively, for the
three and nine months ended
June 30, 2016
. The decrease is primarily due to debt repurchases in the
three and nine months ended
June 30, 2016
.
Other Income—
During the
nine months ended
June 30, 2016
, we recognized approximately
$18.0 million
(
$18.0 million
, net of tax, or
$0.28
per diluted share) of insurance recoveries related to cyclone damage to the
Atwood Osprey
. This amount is included in Other income on the Unaudited Condensed Consolidated Statement of Operations and was subsequently collected.
Income Taxes—
We have historically calculated the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full fiscal year to “ordinary” income or loss (pretax income or loss excluding unusual or infrequently occurring discrete items) for the reporting period. Beginning with the quarter ended December 31, 2016, we used a discrete effective tax rate method to calculate taxes for the
three months ended
June 30, 2017
. We determined that since small changes in estimated “ordinary” income would result in significant changes in the estimated annual effective tax rate that the historical annualized method would not provide a reliable estimate for the
three months ended
June 30, 2017
. We anticipate that we will utilize the discrete effective tax rate method to calculate taxes for the remainder of the fiscal year.
Our estimated consolidated effective income tax rate for the
three and nine months ended
June 30, 2017
was approximately
(146)%
and
(38)%
, respectively, as compared to
17%
and
15%
for the
three and nine months ended
June 30, 2016
, respectively. The effective tax rate for the
three and nine months ended
June 30, 2017
was lower than the rate for the
three and nine months ended
June 30, 2016
, as a result of losses incurred in jurisdictions for which there was no corresponding tax benefit. This included the second quarter non-cash impairment charge against the Atwood Eagle as the charge did not result in a corresponding reduction to our provision for income tax.
LIQUIDITY AND CAPITAL RESOURCES
Sources of Liquidity
Our sources of available liquidity include existing cash balances on hand, cash flows from operations and borrowings under our Credit Facility. In addition, we may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity as necessary, fund additional purchases, exchange or redeem Senior Notes, repay amounts under our Credit Facility or otherwise refinance existing debt. Our ability to access the debt and equity capital markets depends on a number of factors, including our credit rating, industry conditions, general economic conditions, our revenue backlog, capital expenditure commitments, market conditions and market perceptions of us and our industry.
We have agreed in our Merger Agreement with Ensco that, among other things, we will not engage in certain kinds of transactions during the interim period between the execution of the Merger Agreement and the consummation of the Merger, including limitations on our ability to incur debt, issue securities and sell or acquire material assets. If we seek to engage in a restricted activity under these covenants, we are required to obtain the prior written consent of Ensco. We do not anticipate that these contractual limitations will adversely affect our ability to satisfy our liquidity needs during this interim period.
Our liquidity requirements include meeting ongoing working capital needs, repaying our outstanding indebtedness, and funding our capital expenditure projects. Our ability to meet these liquidity requirements will depend in large part on our future operating and financial performance.
Our cash flows fluctuate depending on a number of factors, including, among others, the number of our drilling units under contract, the day rates that we receive under those contracts, the efficiency with which we operate our drilling units, the timing of collections on outstanding accounts receivable, timing of payments to our vendors for operating costs, and capital expenditures. We continue to review and assess previously instituted company-wide cost savings measures, including the elimination of non-essential personnel and other operational measures, including delaying certain capital expenditure projects to ensure liquidity requirements reflect a level of expenditure consistent with the size of our anticipated fleet operating under client contracts over the next twelve months. These activities have had and continue to have a positive impact on our cash flow generation and overall liquidity. We believe that our cash on hand, cash flows from operations and available borrowings under our Credit Facility will provide sufficient liquidity over the next twelve months to fund our working capital needs, interest payments on our outstanding debt and other purposes.
As of
June 30, 2017
, we had
$474 million
in cash on hand. At any time, we may require a portion of our cash on hand for working capital and other purposes. During the
nine months ended
June 30, 2017
, we relied principally on our cash flows from operations and cash on hand to meet liquidity needs and fund our cash requirements including our capital expenditures of
$173 million
. To date, general inflationary trends have not had a material effect on our operating revenues or expenses.
On January 13, 2017, we issued, in a public offering, 15,525,000 shares of common stock. The net proceeds from the offering, before deducting estimated offering expenses, were approximately $181 million. See Note 10 to Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
Cash Flows
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|
|
|
|
|
|
|
|
|
Nine Months Ended June 30,
|
(In thousands)
|
2017
|
|
2016
|
Net cash provided by operating activities
|
$
|
248,828
|
|
|
$
|
515,415
|
|
Net cash used in investing activities
|
(170,908
|
)
|
|
(177,435
|
)
|
Net cash provided by (used in) financing activities
|
250,966
|
|
|
(252,989
|
)
|
Operating Activities
Working capital increased from
$344 million
as of
September 30, 2016
to
$595 million
as of
June 30, 2017
. Net cash from operating activities for the
nine months ended
June 30, 2017
was
$249 million
, as compared to $
515 million
for the
nine months ended
June 30, 2016
, primarily driven by reduced drilling activity.
Investing Activities
Capital Expenditures
Our investing activities are primarily related to capital expenditures for property and equipment. Our capital expenditures, including maintenance capital expenditures, for the
nine months ended
June 30, 2017
and
2016
totaled
$173 million
and
$198 million
, respectively.
As of
June 30, 2017
, we had expended approximately
$980 million
toward our
two
ultra-deepwater drillships under construction at the DSME shipyard in South Korea. Remaining expected capital expenditure for these
two
drillships under construction, including costs associated with the second BOP, totaled approximately
$324 million
at
June 30, 2017
. On December 5, 2016, we entered into supplemental agreements (collectively, "Supplemental Agreement No. 5") to the construction contracts with DSME which delay our requirements to take delivery of our two newbuild ultra-deepwater drillships, the
Atwood Admiral
and the
Atwood Archer
, by two years to
September 30, 2019
and
June 30, 2020
, respectively. Supplemental Agreement No. 5 amends all material terms of the previous supplemental agreements. In consideration of Supplemental Agreement No. 5, we made a payment of
$125 million
for the
Atwood Archer
on December 13, 2016 and will make an additional interim payment of
$15 million
on the earlier of June 30, 2018 or the delivery date. With respect to the
Atwood Admiral,
we will make a payment of
$10 million
on the earlier of September 30, 2017 or the delivery date. Remaining milestone payments,
$83.9 million
for the
Atwood Admiral
and
$165 million
for the
Atwood
Archer,
have been extended until December 30, 2022 through our ability to choose to finance such amounts in the form of promissory notes to be entered into on the delivery dates for each vessel bearing interest at
a rate of
5%
per annum and to be secured by a mortgage on the respective drillship. We have the option to take earlier delivery of each vessel, upon
45
days' notice.
Financing Activities
Our financing activities primarily consist of borrowing and repayment of long-term and dividend payments. Proceeds received from borrowings from our Credit Facility totaled
$125 million
for the
nine months ended
June 30, 2017
. Repayments on our Credit Facility totaled
$55 million
for the
nine months ended
June 30, 2017
.
On January 13, 2017, we issued, in a public offering,
15,525,000
shares of common stock. The net proceeds from the offering, before deducting estimated offering expenses, were approximately
$181 million
. The net proceeds are currently held as cash and are expected to be used for general corporate purposes, which may include the repayment of borrowings under the Credit Facility, the funding of future purchases or redemption of our Senior Notes, working capital and capital expenditures, and otherwise to enhance our liquidity.
Dividends
We paid a dividend of $0.075 per share in January 2016 that was declared in November 2015. In February 2016, our board of directors eliminated the payment of a quarterly dividend in order to preserve liquidity. In March 2016, we amended the Credit Facility, which amendment, among other things, prohibits us from paying dividends during the remaining term of the Credit Facility. Future reinstatement of dividends would require the amendment or waiver of such provision. In addition, the declaration and amount of any future dividends would be at the discretion of our board of directors and would depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our board of directors deems relevant. There can be no assurance that we will pay a dividend in the future.
Senior Notes (Due February 2020)
As of
June 30, 2017
,
$448.7 million
of the aggregate principal amount of our Senior Notes were outstanding. Ou
r Senior Notes are unsecured obligations and are not guaranteed by any of our subsidiaries.
Pursuant to the terms of the indenture governing the Senior Notes, we have the option, on any one or more occasions, to redeem the Senior Notes in whole or in part at a redemption price of 101.625%, if redeemed prior to February 1, 2018, and 100.0% thereafter, in each case plus accrued and unpaid interest to the date of redemption. In addition, we may, from time to time, purchase Senior Notes in the open market, in privately negotiated transactions, through tender offers, exchange offers or otherwise. Any such future redemptions or purchases will depend on various factors existing at that time. There can be no assurance as to which of these alternatives (or combinations thereof), if any, we will pursue in the future.
Under the Merger Agreement, if requested by Ensco, we will issue a notice of redemption providing for the redemption of the Senior Notes substantially concurrently with the closing of the Merger, which redemption will be conditioned upon the closing.
Revolving Credit Facility
As of
June 30, 2017
, our Credit Facility had
$1.395 billion
of total commitments and
$850 million
of outstanding borrowings, providing approximately $518 million available for borrowings without violating financial covenants. Approximately
$275 million
of the commitments under the Credit Facility mature in May 2018 with the remaining
$1.12 billion
of the commitments maturing in May 2019. We were in compliance with all financial covenants under the Credit Facility as of
June 30,
2017
, and we anticipate that we will continue to be in compliance for a least twelve months subsequent to the date our financial statements are issued.
The weighted-average effective interest rate on our long-term debt was approximately
5.1%
per annum as of
June 30, 2017
. The effective rate was determined after giving consideration to the effect of our interest rate swaps accounted for as hedges and the amortization of debt issuance costs and our debt premiums. Interest capitalized for the
nine months ended
June 30, 2017
and
2016
was approximately
$19 million
and
$13 million
, respectively.
The following summarizes our availability under our Credit Facility as of
June 30, 2017
(in millions):
|
|
|
|
|
Commitment under Credit Facility
|
$
|
1,395
|
|
Borrowings under Credit Facility
|
850
|
|
Letters of Credit Outstanding
|
—
|
|
Availability
|
$
|
545
|
|
Letter of Credit Facility
In July 2015, we entered into a letter of credit facility with BNP Paribas (“BNP”), pursuant to which BNP may issue letters of credit up to an unlimited stated face amount of such letters of credit. BNP has no commitment under the facility to issue letters of credit, no amounts are pre-approved for issuance thereunder and the facility may be canceled by BNP at any time. The facility contains certain events of default, including but not limited to delinquent payments, bankruptcy filings, material adverse judgments, cross-defaults under other debt agreements, or a change of control. As of
June 30, 2017
, we have not requested any letters of credits under this facility.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K.
Commitments and Contractual Obligations
For additional information about our commitments and contractual obligations as of
June 30, 2017
, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commitments and Contractual Obligations” in our Annual Report on Form 10-K for the fiscal year ended
September 30, 2016
. As of
June 30, 2017
, other than payments made under our construction contracts, further postponement of the required delivery of the drilling units under construction, repayments under our Credit Facility, and the Supplemental Agreement No. 5 mentioned above, there were no material changes to this disclosure regarding our commitments and contractual obligations.
FORWARD-LOOKING STATEMENTS
Statements included in this Form 10-Q regarding future financial performance, capital sources and results of operations and other statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. Such statements are those concerning strategic plans, expectations and objectives for future operations and performance. When used in this report, the words “believes,” “expects,” “anticipates,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions are intended to be among the statements that identify forward-looking statements.
Such statements are subject to numerous risks, uncertainties and assumptions that are beyond our ability to control, including, but not limited to those summarized below:
|
|
•
|
prices of oil and natural gas and industry expectations about future prices;
|
|
|
•
|
market conditions and level of activity in the drilling industry and the global economy in general;
|
|
|
•
|
the level of capital expenditures by our clients;
|
|
|
•
|
the termination, renegotiation, or repudiation of contracts or payment delays by our clients;
|
|
|
•
|
the operational risks involved in drilling for oil and gas;
|
|
|
•
|
the highly competitive and volatile nature of our business;
|
|
|
•
|
our ability to enter into, and the terms of, future drilling contracts, including contracts for our newbuild units, for rigs currently idled and for rigs whose contracts are expiring;
|
|
|
•
|
our ability to service our indebtedness and make payments on our rigs under construction;
|
|
|
•
|
our ability to access debt and equity capital markets, and the terms and prices that are available if we issue debt or equity securities;
|
|
|
•
|
the impact of governmental or industry regulation, both in the United States and internationally;
|
|
|
•
|
the risks of and disruptions to international operations, including political instability and the impact of terrorist acts, acts of piracy, embargoes, war or other military operations;
|
|
|
•
|
our ability to obtain and retain qualified personnel to operate our vessels;
|
|
|
•
|
unplanned downtime and repairs on our rigs;
|
|
|
•
|
timely access to spare parts, equipment and personnel to maintain and service our fleet;
|
|
|
•
|
client requirements for drilling capacity and client drilling plans;
|
|
|
•
|
the adequacy of sources of liquidity for us and for our clients;
|
|
|
•
|
changes in tax laws, treaties and regulations;
|
|
|
•
|
the risks involved in the construction, upgrade, and repair of our drilling units;
|
|
|
•
|
the possibility that the Company's or Ensco's shareholders may not provide applicable shareholder approval with respect to the Merger;
|
|
|
•
|
the possibility that the Merger Agreement may be terminated under circumstances requiring that the Company pay Ensco a termination fee in an amount equal to $30 million (less any expenses reimbursed by the Company);
|
|
|
•
|
the risk that the Merger Agreement may limit or otherwise restrict strategic or financing options available to the Company;
|
|
|
•
|
the possibility that the pendency of the Merger may adversely affect the business of the Company;
|
|
|
•
|
the risk that the Company and Ensco will not be integrated successfully;
|
|
|
•
|
the possibility that the proposed Merger does not close, including due to failure to satisfy the closing conditions;
|
|
|
•
|
the risk that unexpected costs will be incurred in connection with the proposed Merger;
|
|
|
•
|
the possibility that the expected synergies and value creation from the proposed Merger will not be realized or will not be realized within the expected time period; and
|
|
|
•
|
such other risks discussed in “Risk Factors” in our annual report on Form 10-K for the year ended September 30, 2016 and this Form 10-Q and in our other reports filed with the Securities and Exchange Commission, or SEC.
|
Forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. Undue reliance should not be placed on these forward-looking statements, which are applicable only on the date hereof. We undertake no obligation to revise or update these forward-looking statements to reflect events or circumstances that arise after the date hereof or to reflect the occurrence of unanticipated events.