Sundance Energy - Morgans

Oil & Gas Exp & Prodn│Australia│Equity research│March 29, 2018

Sundance Energy Exploiting the cycle

ADD (previously NOT RATED) Current price: Target price: Previous target: Up/downside: Reuters: Bloomberg: Market cap:

A$0.058 A$0.21 NA 255.3% SEA.AX SEA AU US$102.2m A$133.3m US$0.33m A$0.42m 1,253m 100.0%

Average daily turnover: Current shares o/s Free float: Price Close

Relative to S&P/ASX 200 (RHS)

0.130

110

0.110

94

0.090

78

0.070

62

0.050

46

0.030 60

30

Vol m

40

20 Mar-17

Jun-17

Sep-17

Jan-18

■ Trading at a deep discount to our fully diluted pro-forma valuation, SEA is in the process of completing a transformational acquisition.

■ SEA is pursuing significant expansion of its operating scale and reserves through the acquisition of 21,900 net acres in the Eagle Ford play, funded by an US$260m equity raise, which will also strengthen the company’s balance sheet.

■ After an upgrade to reserves on its existing acreage, SEA has pro-forma 1P reserves of 113mmboe (PV10 of US$738m).

■ Post deal SEA will become one of the largest oil producers listed on ASX. ■ We initiate research coverage on SEA with an Add recommendation and A$0.21 price target.

Material acquisition SEA is raising US$260m in equity via a two-tranche placement and ANREO in order to: 1) fund a US$221m acquisition of 21,900 net acres in the Eagle Ford (EF) play, and 2) strengthen its balance sheet enabling it to fund growth to FCF. A transformational acquisition, SEA will increase its net acres to 56,600, grow production from its current ~9,000 boepd to 21,500-22,500 boepd in 2019, and expand its 1P reserves to 113mmboe (PV10 of US$738m). As a result the acquisition will see SEA emerge as one of the largest oil producers in Australia.

Source: Bloomberg

Risk-reward skew attractive Price performance Absolute (%) Relative (%)

1M -16.9 -13.1

3M 12M -13.6 -48.9 -8.7 -48.3

Adrian PRENDERGAST T (61) 3 9947 4134 E [email protected]

We view SEA as holding an attractive risk-reward skew, with the shale producer holding an opportunity to emerge as one of Australia’s largest oil producers if it can execute on its development plan. Typical of an unconventional E&P, SEA is highly sensitive to oil price volatility, which the company seeks to counter through hedging (enough to cover near-term capex requirements). Meanwhile, post-acquisition SEA will hold significant 1P reserves of 113mmboe and a pro-forma EV of ~A$600m (5.3x EV/1P), which compares well to Australian peer Beach Energy (BPT), which also holds 1P reserves of 113mmboe although has an EV of A$3,140m (27.8x EV/1P) and a similar level of gearing.

FCF generation from 2H19 With all of the acquired acreage already Held By Production (HBP), SEA can prioritise drilling its best targets first (at Live Oak), which hold shorter payback periods. Combined with the extensive production data available on this ground, SEA will be able to proceed immediately into full-scale development (two-rig program drilling 38-40 wells per annum). As a result we expect SEA will reach positive FCF territory in 2H of 2019.

Initiate coverage with an Add rating We initiate research coverage on SEA with an Add rating and a fully diluted valuationderived price target of A$0.21 per share. We view the value proposition offered by SEA as being large enough to absorb the dilution of the significant US$260m equity raise, and expect the remaining ~US$140m of liquidity will be adequate to fund development through to positive FCF generation. The growth profile possible for SEA leaves it looking undervalued relative to peers. The key risk to our call is the oil price, with a sustained +/US$5 per barrel change in oil price impacting our valuation by a significant ~A$0.06ps. Financial Sum m ary Rev enue (US$m) Operating EBITDA (US$m) Net Prof it (US$m) Normalised EPS (US$) Normalised EPS Growth FD Normalised P/E (x) DPS (US$) Div idend Y ield EV/EBITDA (x) P/FCFE (x) Net Gearing P/BV (x) ROE Normalised EPS/consensus EPS (x)

Dec-16A 66.6 47.9 (22.7) (0.010) (68%) NA 0% 4.73 NA 86% 0.28 (6.7%)

Dec-17F 104.3 41.7 11.4 0.009 4.87 0% 5.80 NA 104% 0.31 6.1% -1.30

Dec-18F 219.5 152.2 35.8 0.005 (43%) 8.52 0% 3.12 NA 37% 0.66 11.2% 0.87

Dec-19F 390.8 291.8 88.1 0.013 146% 3.46 0% 1.67 11.04 33% 0.55 17.4% 1.17

Dec-20F 506.1 385.8 128.6 0.019 46% 2.37 0% 1.08 6.19 17% 0.45 20.9%

SOURCE: MORGANS, COMPANY REPORTS

IMPORTANT DISCLOSURES REGARDING COMPANIES THAT ARE THE SUBJECT OF THIS REPORT AND AN EXPLANATION OF RECOMMENDATIONS CAN BE FOUND AT THE END OF THIS DOCUMENT. MORGANS FINANCIAL LIMITED (ABN 49 010 669 726) AFSL 235410 - A PARTICIPANT OF ASX GROUP

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Figure 1: Sundance Energy (SEA) – Financial summary Profit and loss (US$m )

Dec-15A

Dec-16A

Dec-17E

Dec-18E

Dec-19E

Dec-20E

Dec-17E

Dec-18E

Dec-19E

Dec-20E

Revenue

92.2

66.6

104.3

219.5

390.8

506.1

WTI spot price

52.5

57.8

65.0

69.0

Opex

27.4

18.7

62.6

67.3

99.0

120.3

Henry Hub spot price

3.01

2.75

3.25

3.25

EBITDA

64.8

47.9

41.7

152.2

291.8

385.8

% oil hedged

42%

26%

21%

D&A

94.6

48.1

5.3

77.0

124.3

151.9

% gas hedged

20%

12%

10%

EBIT

-29.8

-0.2

36.5

75.2

167.5

233.9

F/cast realised oil price

49.8

57.4

63.0

66.7

-9.4

-12.2

-10.0

-16.6

-23.1

-23.1

F/cast realised gas price

2.43

2.78

3.25

3.22

-39.2

-12.5

26.5

58.6

144.4

210.8 Dec-20E

Net Interest Income Pre-tax Profit Tax

Price assum ptions

0.0

0.0

-15.0

-22.9

-56.3

-82.2

Production (net)

Dec-17E

Dec-18E

Dec-19E

Reported Profit

-361.1

-22.7

11.4

35.8

88.1

128.6

Net oil production (mbbl)

1,799

3,113

5,039

6,237

Exceptional items

-321.9

-10.2

0.0

0.0

0.0

0.0

Net gas production (mcf)

3,508

6,837

10,933

13,124

-39.2

-12.5

11.4

35.8

88.1

128.6

Norm alised Profit

Cash flow statem ent (US$m )

Net NGL production (mbbl)

314

879

1,424

1,704

Total net production (m boe)

2,697

5,131

8,285

10,129

Dec-15A

Dec-16A

Dec-17E

Dec-18E

Dec-19E

Dec-20E

Avg net daily production (boepd)

7,390

13,727

20,287

27,201

EBITDA

64.8

47.9

41.7

152.2

291.8

385.8

Exit rate daily productoin (boepd)

8,333

13,095

24,691

27,966

Net interest

-9.3

-12.2

-10.0

-16.6

-23.1

-23.1

Tax

3.6

0.0

0.0

-22.9

-56.3

-82.2

Changes in w orking capital

11.0

10.5

0.0

2.6

2.3

0.9

Operating cash flow

55.1

30.4

12.8

115.3

214.7

281.4

Capex

-164.7

-67.0

-120.1

-125.5

-227.1

-212.2

Free Cash Flow

-109.6

-36.5

-107.4

-10.2

-12.4

69.2

-15.0

-15.0

15.1

-221.0

0.0

0.0

Total valuation

-1.1

2.0

-3.2

0.0

0.0

0.0

Valuation implied EV/EBITDA

3.6x

-180.8

-80.0

-108.3

-346.5

-227.1

-212.2

Valuation implied EV/2P (A$/boe)

9.4x

Increase / decrease in Equity

0.0

67.5

0.0

247.5

0.0

0.0

Increase / decrease in Debt

Acquisitions and divestments Other Investing cash flow Investing cash flow s

Valuation sum m ary US$m Eagle Ford Operations Net debt Corporate overheads

A$ps

1,722

0.25

-188

-250

-0.04

-45

-61

-0.01

1,058

1,411

0.21

62.0

-0.3

0.5

40.0

40.0

-20.0

Dec-17E

Dec-18E

Dec-19E

Dec-20E

Dividends paid

0.0

0.0

0.0

0.0

0.0

0.0

PE ratio

6.4x

11.1x

4.5x

3.1x

Other financing cash flow s

0.0

0.0

0.0

0.0

0.0

0.0

EV / EBITDA

4.6x

3.1x

1.7x

1.1x

62.0

67.2

0.5

287.5

40.0

-20.0

-12.4x

n.a.

17.9x

7.5x

6.1%

11.2%

17.4%

20.9%

-60.0%

-56.3%

-3.0%

16.8%

-39.81

-1.99

-1.50

6.83

3.0x

1.7x

1.1x

1.7x

Dec-17E

Dec-18E

Dec-19E

Dec-20E

0.9

0.5

1.3

1.9

-8.6

-0.1

-0.2

1.0

Dividend per share (AUD cents)

0.0

0.0

0.0

0.0

Dividend payout ratio

0%

0%

0%

0%

Dec-17E

Dec-18E

Dec-19E

Dec-20E

184.28

170.79

186.24

169.97

103.4%

37.0%

33.9%

25.1%

Financing cash flow s

Key m etrics/ m ultiples

A$m

1,291

EV / EBIT ROE

Balance Sheet (US$m )

Dec-15A

Dec-16A

Dec-17E

Dec-18E

Dec-19E

Dec-20E

Assets Cash And Deposits Debtors Other current assets

FCF per boe (production) (USD) 3.5

17.5

5.8

62.0

89.6

138.8

11.5

9.8

2.8

6.5

10.9

12.4

110.4

27.6

71.3

71.3

71.3

71.3

Total Current Assets Oil & gas properties (incl. explor.)

FCF yield

Current ratio

Per share data EPS (US cents)

277.2

373.1

371.9

641.5

744.3

804.6

7.2

4.2

2.9

2.9

2.9

2.9

Total Non-Current Assets

284.5

377.2

374.9

644.4

747.3

807.6

TOTAL ASSETS

409.8

432.1

454.7

784.2

919.1

1,030.1

0.0

0.0

0.0

0.0

0.0

0.0

Creditors

21.6

3.6

9.0

15.3

22.1

24.5

ND/E

Other current liabilities

20.6

28.2

65.2

65.2

65.2

65.2

ND/[ND+E]

50.8%

27.0%

25.3%

20.0%

Total Current Liabilities

42.2

31.8

74.2

80.5

87.2

89.7

ND/EBITDA

2.8x

3.6x

4.5x

1.1x

Long Term Debt

187.7

188.2

192.0

232.0

272.0

252.0

Interest cover (EBITDA)

6.9x

3.9x

4.2x

9.2x

TOTAL LIABILITIES

233.5

234.3

276.4

322.7

369.4

351.9

308.4

373.6

373.6

621.1

621.1

621.1

-142.4

-188.1

-193.4

-157.6

-69.5

10.3

12.3

-1.9

-1.9

176.4

197.8

178.3

461.5

Other non-current assets

Liabilities Short Term Debt

Gearing

Equity Issued capital Retained earnings Other reserves and FX TOTAL EQUITY

FCF per share (US cents)

ND

Margin analysis

Dec-17E

Dec-18E

Dec-19E

Dec-20E

EBITDA margin

40.0%

69.3%

74.7%

76.2%

59.0

EBIT margin

35.0%

34.3%

42.9%

46.2%

-1.9

-1.9

PBT margin

25.4%

26.7%

37.0%

41.6%

549.6

678.2

NPAT margin

11.0%

16.3%

22.5%

25.4%

SOURCE: MORGANS RESEARCH, COMPANY

2


Transformational acquisition Deal overview SEA is raising US$260m in equity via a two-tranche placement and accelerated non-renounceable entitlement offer. SEA will use these funds to: 1) fund a US$221m EF acquisition, and 2) put its balance sheet back into a position to be able to fund growth. Key details of the US$221m acquisition: 

21,900 net Eagle Ford acres.



Existing production of 1,700 boepd (bringing SEA to 10,700 boepd), to be ramped up to 21,500-22,500 boepd in 2019.



255 net drill locations (282 gross).



100% HBP with 132 historical wells across acreage.



Refinancing of all existing debt, pushing out maturity to 2023.



Ground acquired has higher average oil per foot content (51-77 bbl/ft versus existing acreage 41 bbl/ft), higher liquids mix (76-84% liquids versus existing 60-66% liquids), higher IPs (IP-30 of 1,000-1,200 boepd versus existing acreage 735-865 boepd), and shorter well payback periods (15 month payback period per well versus existing acreage average of 28 months).

Pro-forma SEA: Post the acquisition and raise, SEA will look very different. 

56,600 net EF acres, 614 net (716 gross) drill locations.



Pro-forma current production of 10,700 boepd is planned to be ramped up to 21,500-22,500 boepd in 2019, and close to 30,000 boepd in 2020, which will give SEA significant operating scale.



Increase in 1P reserves to 113 mmboe (pro-forma PV10 of US$738m and EV/1P of 5.3x).



ND/EBITDA will decline from 3.1x in 2017 to a healthier 0.7x in 2019 (on our 2019 forecasts).



Remaining liquidity of c.US$140m in cash and undrawn debt.



Higher oil content per foot of shale across SEA’s acreage portfolio, including a higher liquids production mix, higher average IPs, and shorter well payback periods.



The boost in operating scale will see SEA capable of contracting full-time drill and completion teams (increased operational efficiencies) in addition to putting it on a stronger procurement footing.

Figure 2: Map of acquired EF acreage

SOURCE: COMPANY

3


Investment view Key to our investment thesis is how well we expect SEA will stack up against its peers if it can execute on its development plan. If successful in ramping up production, SEA will emerge as one of the largest oil producers on the ASX, at a time when the market is positively re-rating the sector. This growth profile, combined with our A$0.21 per share valuation, are core reasons behind our Add recommendation. We note the key risks associated to achieving our target price are: 1) SEA’s large valuation sensitivity to oil price, and 2) execution risk (refer to the Key risks section on page 9 of this report for further details). Attractive on expanded reserve base Key to our investment view is the upside potential held by SEA post this acquisition, which on our estimates leaves it looking significantly undervalued relative to its Australian peers. Post-acquisition SEA will hold significant 1P reserves of 113mmboe and a pro-forma EV of ~A$600m (5.3x EV/1P), which compares well to Australian peer Beach Energy (BPT), who also holds 1P reserves of 113mmboe although has an EV of A$3,140m (27.8x EV/1P) and a similar level of gearing. SEA also looks undervalued compared to its US-listed EF peers, with only the gas-heavy (lower value) reserves of SilverBow or debt-laden EV of Lonestar Resources putting these two E&Ps on smaller EV/1P multiples. Potential for attractive earnings power Looking at the potential growth SEA’s new acreage can leverage leaves the company with an attractive forward earnings profile. On our forecasts SEA will be trading on a pro-forma forward EV/EBTIDAX multiple of 1.7x in 2019. This compares to an average of 8.6x for its Australian peers, and US peer average of 4.2x. While we value resources using DCF, a look at the earnings multiples does demonstrate the potential earnings power SEA holds, which we expect will see it materially re-rated once the company gets into its planned two-rig development program of 38-40 wells per annum (to kick off in 2H 2018). Figure 3: Reserve multiple comparison (SEA & BPT pro-forma numbers) 100x 90x

88x

80x 70x 60x

50x

50x 40x 30x

32x 32x 25x

28x 29x

29x

28x

20x

28x

25x

22x

16x

21x 14x

14x

14x

6x

10x

9x

6x

5x 4x

4x 3x

SEA

SEH

0x

OEL

HZN

OSH

STO

SXY

WPL

EV/1P reserve

BPT

ELK

COE

CTP

EV/2P reserve

SOURCES: MORGANS, COMPANY REPORTS

4


Figure 4: Sector comparison US-BASED PEER COMPARISON

Market

Currency

Last 1P Reserve

Mcap

Net Debt

EV

$ps

MMBOE

$m

$m

$m

$/MMBOE

EV/1P EV/EBITDAX ND/EBTIDAX x

x

INDEPENDENT EAGLE FORD PLAYERS Wildhorse Resource Development Corp**

WRD.NYS

US

USD

17.91

175

1,811

1,222

3,033

17.3x

4.9x

1.2x

Penn Virginia Corp**

PVAC.NAS

US

USD

34.96

57

525

255

780

13.7x

3.0x

1.0x

SilverBow Resources (mostly gas)**

SBOW.NYS

US

USD

28.82

149

333

259

592

4.0x

3.9x

1.7x

Lonestar Resources**

LONE.NAS

US

USD

3.99

77

87

367

454

5.9x

6.9x

3.1x

Carrizo Oil & Gas**

CRZO.NAS

US

USD

15.55

200

1,267

1,870

3,137

15.7x

4.6x

2.4x

Sanchez Energy Corp**

SN.NYS

US

USD

3.07

343

258

1,774

2,032

5.9x

3.6x

3.2x

Freedom Oil & Gas**

FDM.ASX

AU

AUD

0.29

6

259

-9

250

39.0x

n.a.

n.a.

Sundance Energy*

SEA.ASX

AU

AUD

0.06

113

411

188

599

5.3x

1.7x

0.7x

AVERAGE

140

619

741

1,360

13.3x

4.1x

1.9x

MEDIAN

131

372

313

689

9.8x

3.9x

1.7x

Last 1P Reserve 2P Reserve

*Pro-forma numbers post acquisition AUSTRALIAN PEER COMPARISON

Currency

Mcap

Net Debt

EV

EV/1P

$ps

MMBOE

MMBOE

$m

$m

$m

$/MMBOE

EV/2P EV/EBITDAX x

x

AUSTRALIAN LISTED OIL & GAS PRODUCERS Beach Energy**

BPT.ASX

AUD

1.20

113

232

2,280

860

3,140

27.8x

13.5x

4.11x

Senex Energy

SXY.ASX

AUD

0.39

17

84

566

-80

486

29.1x

5.8x

26.57x

Cooper Energy**

COE.ASX

AUD

0.31

8

12

370

-204

166

21.1x

14.2x

5.55x

Sino Gas & Energy**

SEH.ASX

AUD

0.18

64

97

363

-100

263

4.1x

2.7x

n.a.

Santos

STO.ASX

AUD

5.02

470

848

10,192

3,641

13,834

29.4x

16.3x

6.31x

Oil Search

OSH.ASX

AUD

7.13

455

515

10,856

3,515

14,371

31.6x

27.9x

9.73x

Woodside Petroleum

WPL.ASX

AUD

28.71

1,012

1,334

24,457

4,286

28,743

28.4x

21.5x

5.95x

Horizon Oil**

HZN.ASX

AUD

0.13

5

8

163

88

251

50.3x

31.8x

3.83x

Buru Energy**

BRU.ASX

AUD

0.31

0

1

134

-9

125

n.a.

124.6x

5.13x

Central Petroleum

CTP.ASX

AUD

0.12

15

21

85

52

136

9.2x

6.5x

9.75x

Otto Energy**

OEL.ASX

AUD

0.06

1

3

76

-6

70

88.0x

25.1x

Elk Petroleum**

ELK.ASX

AUD

0.09

AVERAGE MEDIAN

11

20

79

203

281

25.1x

14.1x

9.19x

181

265

4,135

1,020

5,156

31.3x

25.3x

8.6x

16

52

367

70

272

28.4x

15.3x

6.1x

** Bloomberg consensus Prices as at 28 March 2018. SOURCE: MORGANS RESEARCH, COMPANY DATA, BLOOMBERG

Development plan The advantage of mature ground A key advantage held by this ground is the fact that historical drilling of 132 production wells (mostly drilled in 2012/13) has satisfied drilling obligations. As a result, with all of the new ground HBP, SEA will be able to prioritise drilling and focus development on the areas with the shortest payback periods (Live Oak). This will also support launching straight into a full-scale two-rig development program (continuous drilling of 38-40 wells per annum), as SEA will be able to proceed straight into pad drilling (2-4 wells per pad), rather than drilling one-off wells to satisfy lease requirements in order to hold onto ground (a common problem for smaller shale producers). The faster development pace helps promote operational efficiencies such as accessing lower contractor rates by being able to hire full-time drilling and completion crews, as well as increasing bargaining power when it comes to procurement of inputs. Another advantage of mature ground is the fact that the historical drilling (that was drilled on circa 2012 industry best practice: i.e. tight well spacings, shorter laterals and smaller fracs) has left SEA a considerable bank of production data. As a result SEA will be able to conduct essentially an in-fill drill program to drill out the acquired well inventory while rolling out current day (i.e. much improved) industry best practice, namely: a) wider well spacings (meaning fewer wells required), b) +6,000 foot laterals (longer wells recovering more oil/gas), and c) ~2,200lb/ft proppant concentration (larger fracs unlocking more resource).

5


Production profile We have assumed capex of ~US$120m in 2018 and the drilling of 22 wells, with drilling activity ramping up mainly in Q4. As a result the bulk of the production growth will be experienced in 2019, when we expect steady development of 3840 wells and annual development capex of ~US$200mpa to be reached. In 2020 we expect production rates to peak at around 30,000 boepd. In the long term we expect production to shrink as SEA drills out its best acreage (Live Oak and Atascosa) and progresses into La Salle and McMullen Counties. An upside scenario to this base case would be an improvement in type curves. Figure 5: Morgans' forecast for SEA production (boepd) 35,000

30,000

25,000

20,000

15,000

10,000

5,000

Sep-18

Mar-19

Sep-19

Mar-20

Sep-20

Mar-21

Sep-21

Mar-22

Sep-22

Mar-23

Sep-23

Mar-24

Sep-24

Mar-25

Existing prod'n on Pioneer acreage Existing prod'n SEA acreage

Live Oak LLEF

Live Oak ULEF

Live Oak ASTN

Atascosa LEF

La Salle LLEF

La Salle ULEF

La Salle UEF

La Salle LLEF (F)

La Salle ULEF (F)

McMullen LLEF

McMullen ULEF

McMullen UEF

McMullen LLEF (F)

McMullen ULEF (F)

Dimmit LEF

Sep-25


Road to positive FCF Besides boosting scale, the deal improves the quality of SEA’s acreage. On our estimates, the payback period of SEA’s wells on average will improve from 28 months pre-acquisition to a pro-forma combined average of 17 months average payback period (with the acquired acreage averaging a 15-month payback period on capex sunk on our estimates).

6


Figure 6: Estimated well payback times (months to breakeven) 54 months 39 months

40

35

30

28 months 24 months

25

19 months

20

21 months 20 months

22 months

17 months

17 months 15 months

14 months

15 10 months

11 months

10

5

0

SOURCES: MORGANS

If management can execute its development plan and achieve average production results similar to the type curves, then we expect SEA to switch gears into heavy FCF generation from 2H 19 onwards, with potential FCF yield of +20% achievable based on our estimates of oil/gas prices, opex, production and capex. Figure 7: EBITDA and FCF outlook (US$m) 500

30% 20%

400

10% 0%

300

-10% 200

-20% -30%

100

-40% -50%

0

CY17

CY18

CY19

CY20

CY21

CY22

CY23

CY24

-100

CY25

-60% -70%

FCF (LHS)

EBITDA (LHS)

FCF Yield (RHS) SOURCES: MORGANS, COMPANY REPORTS

7


Valuation Valuation by play Our modelling and testing of operational assumptions highlights the uplift in value we believe SEA will be capable of adding with the drill bit by adding the Pioneer acreage to its portfolio. In order of value per well, we rank SEA’s acreage by county as: 1) Live Oak, 2) Atascosa, 3) La Salle, 4) McMullen, and 5) Dimmit, with our model assuming drilling locations are developed in this order. Our base case valuation on SEA does not attribute value to all plays within its EF acreage, with the Austin Chalk in Live Oak, upper Eagle Ford in La Salle and McMullen, and SEA’s acreage in Dimmit County assumed as not developed. At this stage we see drilling of these plays as unlikely to occur. Comparing areas highlights upside case If SEA can improve on the independent expert’s type curves for La Salle and McMullen (where a large number of drill locations sit), it could greatly boost the long-term value proposition and prevent FCF generation from drifting in future years (+2024). Figure 8: Valuation per play Area County Play

LLEF

Area 41

Area 41

Area 11

Live Oak

Atascosa

La Salle

ULEF AstnChk

Area 21

Area 32 McMullen

Dimmit

LEF

LLEF

ULEF

UEF

LLEF

ULEF

LLEF

ULEF

UEF

LLEF

ULEF

LEF

Net well locations

36

68

16

35

26

29

4

21

21

5

5

2

93

118

146

IP-30 (days) (boe)

1,216

1,216

2,004

778

683

682

665

864

864

1,084

1,084

536

865

855

737

766

766

482

601

479

478

478

363

363

488

488

387

461

451

354

1,170

1,170

5,400

462

612

612

612

1,452

1,452

1,560

1,560

480

1,902

1,902

1,284

255

255

622

100

102

102

85

259

259

336

336

69

87

87

169

77

77

77

63

51

51

51

51

51

49

49

49

41

41

% Oil

63%

63%

24%

77%

70%

70%

72%

42%

42%

45%

45%

72%

49%

48%

39%

% Liquids

84%

84%

55%

90%

85%

85%

85%

72%

72%

76%

76%

85%

60%

60%

66%

NPV per well (US$m)

5.1

5.1

4.6

3.3

2.4

2.1

2.1

1.8

1.8

2.7

2.7

-0.1

2.0

1.9

0.7

Unrisked valuation

184

347

73

114

64

62

8

38

38

13

13

-0

190

227

104

Development factored in:

Yes

Yes

No

Yes

Yes

Yes

No

Yes

Yes

Yes

Yes

No

Yes

Yes

No

Base case val'n (US$m)

184

347

-

114

64

62

-

38

38

13

13

-

190

227

-

Payback period (months)

10

10

11

14

19

21

22

24

24

17

17

54

19

20

39

IP-30: Oil (bbl) IP-30: Gas (mmcf) IP-30: NGL (bbl) Barrels of oil per foot


Valuation summary Using a 10% discount rate we arrive at a group NAV for SEA of US$1,058m (or A$0.21 per share). Unlike emerging plays, SEA holds a development portfolio of mature acreage, which we have valued through each play's established analogs. This implies SEA’s fair value is 3.6x EV/EBITDAX, on par with SEA’s US peers but still less than half the average EV/EBITDAX of its Australian peers (8.6x), showing the potential for SEA to rally beyond fair value if it can execute its development plan. Figure 9: SEA valuation Valuation sum m ary US$m Eagle Ford Operations Net debt Corporate overheads Total valuation Valuation implied EV/EBITDA Valuation implied EV/2P (A$/boe)

A$m

A$ps

1,291

1,722

0.25

-188

-250

-0.04

-45

-61

-0.01

1,058

1,411

0.21 3.6x 9.4x SOURCE: COMPANY

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Key risks 

Oil price. Given SEA is a resource-style oil and gas producer (a capitalintensive bulk activity style business), it increases the company’s sensitivity to volatility in the oil price. This is typical of unconventional oil and gas producers, which are the most leveraged to oil and gas prices.



Execution. Another significant risk we see for SEA will come down to management’s ability to execute on its plan.



Meeting midstream contracts. Significant operational underperformance could see SEA fall short of minimum contracted volume requirements under its midstream contracts, which would result in SEA having to fund the deficiency in volume.



Financial risk. Regardless of excess liquidity of US$140m, pro-forma net debt of US$188m still represents gearing in excess of 40%, significant for a producer that has not yet expanded production.

Acquisition background Deal orientation We identify three key reasons why previous owner Pioneer and its partners would be motivated to divest this ground to SEA. 1. Legacy midstream contracts. Pioneer’s EF ground is burdened by legacy midstream contracts (we estimate in the range of US$10-$15/boe) that were set when Pioneer originally divested its EF midstream infrastructure. Importantly SEA has negotiated a market rate with the midstream service provider that will see it improve margins in the range of US$6-$13/boe. 2. Rush to Permian. The Eagle Ford has lost popularity amongst the major E&Ps, with years of heavy development reducing the ‘run room’ and scalability available to the majors. As a result, large E&Ps such as Pioneer have responded by shifting their development focus to the underdeveloped Permian Basin (with its multiple stacked plays). 3. The introduction of capital discipline. The magnitude of swings in oil prices in recent years, as the market entered a severe downturn and subsequent recovery cycle, has reduced investor and lender appetite for risk. As a result US E&Ps have had to ‘do more with less’ and introduce some discipline to their deployment of capital. We expect this has added to the current divestment drive from the majors as they reshuffle asset portfolios to reflect updated priorities. Given the above observations we expect Pioneer to continue its well-flagged plan of exiting the Eagle Ford, despite there still being attractive opportunities for smaller players such as SEA to still produce high margin/value barrels. Acreage location SEA is acquiring the 21,900 net EF acres from a JV headed up by Pioneer Natural Resources, and its partners Reliance Eagleford Upstream and Newpek. The majority of acres being acquired sits within the volatile oil and oil windows in the Eagle Ford play, located in Live Oak, Atascosa, La Salle and McMullen Counties.

9


Figure 10: Map of acquired EF acreage

SOURCE: COMPANY

Reserve increase This week SEA updated its 1P reserve estimates on its existing acreage, which increased from 22.3 mmboe to 47.1 mmboe as at 31 December 2017. Proved undeveloped reserves increased by 53% to 31.3 mmboe, following successful testing of the upper lower Eagle Ford in McMullen County, lease additions in McMullen, and a better performance from 2017 wells in Dimmit County. Excluding the additional reserves from the acquisition, this increases SEA’s pretax 1P PV10 to US$423m (A$542m) on its existing acreage, up from US$336m.

Hedging SEA has sought to hedge significant portions of production over the next three years (rolling) in order to underpin its large capex spend and protect against oil price volatility. Normally we prefer unhedged resource companies, except in cases such as SEA where a company is rolling out material expansion funded by a large amount of debt. Figure 11: Hedging positions

(1)

As at 31 December 2017 SOURCE: COMPANY

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Management and board Management team 

Eric McCrady – MD & CEO



Cathy Anderson – CFO



Grace Ford – COO



Keith Kress – VP Operations



Trina Medina – VP Reservoir Engineering



Mike Wolfe – VP Land

Board 

Mike Hannell – Chairman



Eric McCrady – MD & CEO



Damien Hannes – NE Director



Weldon Holcombe – NE Director



Neville Martin – NE Director

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